365 1 state of michigan 2 before the michigan public

365

1 STATE OF MICHIGAN

2 BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

3 In the matter, on the Commission's Own

Motion establishing the method and Case No. U-18091

4 avoided cost calculation for DTE

Electric Company to fully comply with Volume No. 3

5 Public Utilities Regulatory Policy

Act of 1978, 16 USC 2601 et seq.

6 _____________________________________/

7 REOPENED CROSS-EXAMINATION

8 Proceedings held in the above-entitled matter

9 before Martin D. Snider, J.D., Administrative Law Judge

10 with MAHS, at the Michigan Public Service Commission,

11 7109 West Saginaw Highway, Lake Superior Room, Lansing,

12 Michigan, on Wednesday, September 13, 2017, at 10:06 a.m.

13 APPEARANCES:

14 JON P. CHRISTINIDIS, ESQ.

DTE Energy

15 One Energy Plaza, #688WCB

Detroit, Michigan 48226

16

On behalf of DTE Electric Company

17

TONI L. NEWELL, ESQ.

18 Varnum Riddering Schmidt Howlett, LLP

Bridgewater Place, P.O. Box 352

19 Grand Rapids, Michigan 49501-0352

20 On behalf of City of Ann Arbor

21 HEATHER M.S. DURIAN,

Assistant Attorney General

22 7109 West Saginaw Highway, Floor 3

Lansing, Michigan 48917

23

On behalf of Michigan Public Service

24 Commission Staff

25 REPORTED BY: Lori Anne Penn (CSR-1315)

Metro Court Reporters, Inc. 248.360.8865

366

1 I N D E X

2 WITNESS: PAGE

3 DAVID SWIECH

4 Testimony Bound In 373

5 LAURA K. MIKULAN

6 Testimony Bound In 382

7 TIMOTHY A. BLOCH

8 Direct Examination by Mr. Christinidis 398

Cross-Examination by Ms. Newell 417

9

JULIE K. BALDWIN

10

Testimony Bound In 424

11

JESSE J. HARLOW

12


13

BRIAN STEGLITZ

14


15

DOUGLAS B. JESTER

16


17

18

19

20

21

22

23

24

25


367

1 E X H I B I T S

2 NUMBER DESCRIPTION MRKD OFRD RECD

3 A-10 Inputs for Staff’s Hybrid Proxy 369 381 381

Plant Avoided Cost Calculation

4

A-11 Capacity and ICE Calculations 369 381 381

5

A-12 NGCC levelized variable cost 369 381 381

6

A-13 Levelized LMP Forecast 369 381 381

7

A-14 EIA Cost and Performance 369 381 381

8 Characteristics of New Generating

Technologies, Annual Energy Outlook

9 2017

10 A-15 NGCC Heat Rate and Capacity Factor 369 381 381

11 A-16 Proposed Project Capital Cost 369 381 381

12 A-17 Fixed Charge Rate Calculation 369 381 381

13 A-18 Avoided Cost by Technology 369 381 381

14 A-19 Proposed Tariff Sheet - Standard 369 400 400

Contract Rider No.5

15

A-20 Capacity and Energy Cost Comparison 369 400 400

16 – Staff Proposed Standard Offer

Tariff versus DTE Natural Gas

17 Combined Cycle Plant

18 A-21 Henry Hub Price Forecast Accuracy 369 372 372

– EIA Annual Energy Outlook 2009

19 - 2015

20 A-22 Henry Hub Price Forecast Accuracy 369 372 372

– Market Forwards 2009 - 2015

21

A-23 Henry Hub Price Forecast Accuracy 369 372 372

22 – PACE vs EIA AEO 2014-2015

23 - - -

24 ELP-9 Natural Gas Price Forecasts 369 459 459

25 ELP-10 Proposed Final Energy Rate 369 459 459


368

1 E X H I B I T S

2 NUMBER DESCRIPTION MRKD OFRD RECD

3 CAA-24 Standard Offer Tariff 369 451 451

4 - - -

5 S-7 (JKB-3) Staff’s Proposed Reopened 369 422 423

Standard Offer Tariff

6

S-8 (JJH-5) Pages 1-2, MPSC Staff’s 369 422 423

7 Avoided Cost Methodology and

Calculation

8

S-8.1 (JJH-6) Pages 1-3, MPSC Staff’s 369 422 423

9 Variable Natural Gas Combined Cycle

(NGCC) Plant Cost (Avoided Energy

10 Cost)

11 S-8.2 (JJH-7) Twenty Year LMP Projections 369 422 423

12 S-8.3 (JJH-8) Schedule of Annual Avoided 369 422 423

Energy Cost Payments

13

S-9 Staff’s Proposed Rider No. 5 (Based 369 422 423

14 on DTE Exhibit A-19)

15 S-9.1 Staff’s Proposed Rider No. 5 369 422 423

(Applicable to Standard Offer

16 Projects Only)

17 S-10 (JJH-9) Pages 1-2, MPSC Staff’s 369 422 423

Avoided Cost Methodology and

18 Calculation

19 S-10.1 (JJH-10) Pages 1-3, MPSC Staff’s 369 422 423

Variable Natural Gas Combined

20 Cycle (NGCC) Plant Cost (Avoided

Energy Cost)

21

S-10.2 (JJH-11) Twenty Year LMP Projections 369 422 423

22

S-10.3 (JJH-12) Schedule of Annual Avoided 369 422 423

23 Energy Cost Payments

24

25


369

1 Lansing, Michigan

2 Wednesday, September 13, 2017

3 At 10:06 a.m.

4 - - -

5 (Hearing continues pursuant the July 31, 2017,

6 Commission Order.)

7 (Documents marked for identification by the Court

8 Reporter as Exhibit Nos. A-10 through A-23; ELP-9,

9 ELP-10; CAA-24; S-7, S-8, S-8.1, S-8.2, S-8.3, S-9,

10 S-9.1, S-10, S-10.1, S-10.2, S-10.3.)

11 - - -

12 JUDGE SNIDER: All right. We're on the

13 record in the matter of the Commission's own motion

14 establishing the method and avoided cost calculation for

15 DTE Electric Company to fully comply with the Public

16 Utility Regulatory Policies Act of 1978, 16 USC 2601

17 et seq. The case number is U-18091. And this hearing is

18 being held pursuant to the Commission's order of July 31,

19 2017, where the Commission indicated in its order that it

20 was reopening the record in this matter. The parties had

21 until August 15, 2017, to submit proposed inputs for

22 avoided cost capacity using a natural gas combustion

23 turbine unit and avoided cost capacity and avoided energy

24 cost combined cycle unit as proxy plants, the calculation

25 of the investment cost attributable to energy. And then


370

1 the order also indicated the parties were to file a

2 proposed final cost calculations, a standard offer tariff

3 which includes all forecasts as described in the

4 Commission's order. The parties were allowed to file

5 responses to those initial filings by August 31, 2017.

6 And then, finally, I was ordered to convene this hearing

7 today and to introduce into evidence all those filings,

8 and in addition, to set a briefing schedule so the

9 Commission can read the record in this matter by

10 October 5, 2017. So that is why we're here today.

11 Who's appearing on behalf of DTE Energy

12 Company?

13 MR. CHRISTINIDIS: Jon Christinidis, your

14 Honor, on behalf of DTE Electric Company.

15 JUDGE SNIDER: O.K. And who's appearing

16 on behalf of Michigan Public Service Commission Staff?

17 MS. DURIAN: Heather Durian on behalf of

18 Michigan Public Service Commission Staff.

19 JUDGE SNIDER: All right. Any other

20 appearances today?

21 MS. NEWELL: Yes, your Honor. Toni

22 Newell from the Varnum Law Firm appearing on behalf of

23 the City of Ann Arbor.

24 JUDGE SNIDER: All right. And,

25 Mr. Christinidis, I know off the record there was some


371

1 stipulations that were made about how we would proceed

2 today. You want to go over those?

3 MR. CHRISTINIDIS: Yes, your Honor. It's

4 the Company's understanding that the parties have agreed

5 to bind in all testimony in this reopened portion of the

6 proceeding and waive cross-examination for all witnesses,

7 with the exception of DTE Electric's Mr. Bloch, who the

8 Company has with us here today so we can tender him for

9 cross-examination by Ann Arbor.

10 JUDGE SNIDER: All right. Is that

11 Staff's understanding?

12 MS. DURIAN: Yes, your Honor.

13 JUDGE SNIDER: And, Ms. Newell, you'll be

14 doing the cross of Mr. Bloch; is that right?

15 MS. NEWELL: That's correct, your Honor.

16 JUDGE SNIDER: All right.

17 Mr. Christinidis, would you like to begin?

18 MR. CHRISTINIDIS: I'd be happy to, your

19 Honor. The Company's reopened case consists of testimony

20 from Ms. Laura K. Mikulan, Mr. David Swiech, and Mr. Tim

21 Bloch. I would at this point proceed to bind in the

22 testimonies of Mr. Swiech and Ms. Mikulan.

23 Mr. Swiech's testimony is, his

24 qualifications and rebuttal testimony consists of a cover

25 sheet and seven pages of questions and answers. He also,


372

1 accompanying that testimony, is sponsoring three exhibits

2 that have been marked as Exhibits A-21, A-22, and A-23,

3 and those are all one-page exhibits. With that, your

4 Honor, the Company would move to bind the qualifications

5 and reopened rebuttal testimony of David Swiech into the

6 record, and move the admission of Exhibits A-21, A-22,

7 and A-23.

8 Would you like me to continue?

9 JUDGE SNIDER: I can admit those first

10 and we'll move on to the next one.

11 Based on the stipulation of the parties,

12 the reopened testimony and rebuttal reopened testimony of

13 Mr. Swiech is bound into the record; and Exhibits A-21,

14 A-22, and A-23 are admitted.

15 (Testimony bound in.)

16 - - -

17

18

19

20

21

22

23

24

25


STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter, on the Commissions own motion, ) establishing the method and avoided cost calculation ) for DTE ELECTRIC COMPANY to fully ) Case No. U-18091 comply with the Public Utilities Regulatory ) Policy Act of 1978, 16 USC 2601 et seq. )

QUALIFICATIONS

AND

REOPENED REBUTTAL TESTIMONY

OF

DAVID SWIECH

373

DTE ELECTRIC COMPANY QUALIFICATIONS OF DAVID SWIECH

Line No.

Reopened Rebuttal DS - 1

Q. Would you please state your name and position? 1

A. My name is David Swiech. My position is Manager, Planning and Procurement, 2

within the Fuel Supply department. 3

4

Q. What is your business address and on whose behalf are you testifying? 5

A. My business address is One Energy Plaza, Detroit, Michigan 48226. I am testifying 6

on behalf of DTE Electric Company (Company or DTE Electric). 7

8

Q. What is your educational background? 9

A. I received a Bachelor of Science degree in Mechanical Engineering from the 10

University of Michigan in 2001 and a Master of Business Administration degree from 11

the University of Michigan’s Stephen M. Ross School of Business in 2010. 12

13

Q. Please summarize your professional experience. 14

A. I have been employed by DTE Energy since 2010. From 2010 through 2012, I held 15

various positions within the Controller’s Organization, including budgeting and 16

forecasting for DTE Gas Company (DTE Gas), corporate capital planning and 17

analysis, and financial support for DTE Electric’s Renewable Energy Program. In 18

2013, I joined DTE Gas’s Midstream Services group as a Marketing Program 19

Manager. In this role, I marketed and sold natural gas storage and transportation 20

services to off-system customers. In late 2013, I was promoted to manage the 21

optimization of DTE Gas’s storage and transmission assets, and performed that 22

function through early 2016. In 2016, I transferred to the Fuel Supply department of 23

DTE Electric as Manager, Planning and Procurement. 24

25

374

D. SWIECH Line U-18091 No.


Prior to joining DTE Energy, I worked for American Mitsuba Corporation from 2002 1

– 2005, and ASMO Detroit, Inc from 2005 – 2010. During this time, I was 2

responsible for the design and development of small motor applications in the 3

automotive industry. 4

5

Q. What are your duties and responsibilities in your current position? 6

As Manager, Planning and Procurement, I have the responsibility of managing the 7

Company’s purchases of fossil fuels and associated transportation used for electric 8

generation. I also have the responsibility of managing the Company’s preparation of 9

budgets and forecasts regarding all fossil fuels used for electric generation. 10

11

Q. Have you previously sponsored testimony before the Michigan Public Service 12

Commission (MPSC or Commission)? 13

A. Yes. I sponsored rebuttal testimony in the DTE Electric 2016 Power Supply Cost 14

Recovery (PSCR) Plan, Case No. U-17920. I also sponsored testimony in the 15

Company’s Application for Approval of Certificates of Necessity for a natural gas 16

combined cycle generating facility, Case No. U-18419. 17

18

Q. Have you provided support to other DTE Electric witnesses in cases before the 19

Michigan Public Service Commission? 20

A. Yes, I have provided support to other DTE Electric witnesses in the following cases: 21

U-16991 Renewable Energy Depreciation Case 22

U-16656 2011 Renewable Energy Plan Reconciliation 23

375

DTE ELECTRIC COMPANY REOPENED REBUTTAL TESTIMONY OF DAVID SWIECH

Line No.


Q. What is the purpose of your testimony in this proceeding? 1

A. The purpose of my testimony is to rebut Michigan Public Service Commission Staff 2

(Staff) Witness Mr. Harlow and Environmental Law and Policy Center (ELPC) 3

Witness Mr. Jester’s recommended use of the Energy Information Administration 4

(EIA) projected natural gas price forecast. In addition, I am rebutting the natural gas 5

transportation costs proposed by Staff and the ELPC. My rebuttal to the indicated 6

inputs to Staff’s Hybrid Proxy Plant Methodology, of course, should not be construed 7

as agreement with the Staff Hybrid Proxy Plant Methodology as the proper means to 8

determined DTE Electric’s avoided costs. 9

10

Q. Are you sponsoring any exhibits in the proceeding? 11

A. Yes, I am sponsoring the following exhibits: 12

Exhibit Description 13

A-21 Henry Hub Price Forecast Accuracy – EIA Annual Energy Outlook 14

2009 - 2015 15

A-22 Henry Hub Price Forecast Accuracy – Market Forwards 2009 - 2015 16

A-23 Henry Hub Price Forecast Accuracy – PACE vs EIA AEO 2014- 17

2015 18

19

Q. Were these exhibits prepared by you or under your direction? 20

A. Yes, they were. 21

22

NATURAL GAS PRICE FORECAST 23

Q. What natural gas price forecast do Staff and the ELPC recommend for use in 24

the avoided cost calculation? 25

376



A. The Staff and ELPC recommend the use of the natural gas price forecast from the 1

EIA’s 2017 Annual Energy Outlook (AEO). 2

3

Q. Do you agree with the use of the EIA gas price forecast? 4

A. No, I do not agree with the use of the EIA AEO for the gas price forecast. 5

6

Q. Please explain why you do not agree with using the EIA AEO for the gas price 7

forecast. 8

A. The EIA forecasts have historically been higher than the actual price of gas. Exhibit 9

A-21 shows the EIA nominal Henry Hub Natural Gas Spot Price projections 10

published from 2009 – 2015 in lines 4-10. Line 1 shows the actual Henry Hub spot 11

prices from 2010 – 2016. Lines 13-20 show the percent error of the forecasts 12

compared to the actual prices. 13

14

This exhibit demonstrates that the EIA forecasted price for individual years in 2010 15

– 2016 were higher than the actual price in 27 out of 28 predictions. These 16

predictions averaged 82% higher than actual, with the percent error being as much as 17

229%. While all forecasts contain error, one would expect that multiple unbiased 18

forecasts would produce some predictions that are higher than actual and some 19

predictions that are lower than actual. 20

21

Q. What gas price forecast should be used in the proposed avoided cost calculation? 22

A. The Company’s Henry Hub natural gas price forecast should be used in the avoided 23

cost calculation. The first five years of this forecast is consistent with the 24

methodology used in the Company’s annual Power Supply Cost Recovery (PSCR) 25

377



Plan cases – utilizing market forwards for this time period. Exhibit A-22 shows the 1

historical accuracy of the market forwards. While the market forwards have been 2

higher than actual prices in recent history, they have been more accurate than the EIA 3

AEO projections. 4

5

For the longer term gas price forecast where the forward market is less liquid and 6

pricing is less reliable, the Company utilized the expertise of PACE Global 7

Consulting (PACE). The Company has used PACE in this capacity since 2014. 8

While this is a limited sample of forecasts, PACE’s 2014 and 2015 forecast accuracy 9

can be compared against the EIA AEO for years 2015-2016. Exhibit A-23 shows 10

this comparison. Like the market forwards, PACE’s forecasts were also more 11

accurate than the EIA AEO gas price forecasts. As a result, the Company 12

recommends using the Henry Hub gas price forecast presented by DTE Electric 13

Company Witness Ms. Mikulan in Exhibit A-12, page 1, column (g). 14

15

NATURAL GAS TRANSPORTATION COSTS 16

Q. What natural gas transportation cost does Staff recommend for use in the 17

avoided cost calculation? 18

A. Witness Harlow on page 11, lines 7-10, states that the “gas transportation cost was 19

provided by the Consumers Energy Company. It represents the price to transport gas 20

from the Henry Hub to Consumers Energy Company’s proxy plant. Its basis is a 21

levelized tariff rate which should be very comparable to DTE Electric’s rate.” In 22

Exhibit S-8.1 (JJH-6), Witness Harlow states a gas transportation component of the 23

Levelized Fuel Price of $0.54/MMBtu. 24

25

378



Q. Do you agree that the transportation cost recommended by Staff is appropriate 1

to use for DTE Electric’s NGCC avoided cost? 2

A. No. Gas transportation costs depend heavily on the location of the generating plant 3

and contracts with the natural gas pipeline company providing the transportation. 4

Therefore, using the transportation costs for a Consumers Energy plant fails to 5

accurately reflect the cost that the Company would incur to transport gas to DTE 6

Electric’s plant. Instead, the only reasonable approach would be to utilize the 7

estimates provided for the NGCC generation plant proposed by DTE Electric in 8

MPSC Case No. U-18419 since these are specific to DTE Electric. 9

10

Q. How did the Company forecast the delivered natural gas price for this proposed 11

generation plant? 12

A. The proposed generation plant will be located at the Company’s Belle River Power 13

Plant site. Therefore, the forecast relies on the Company’s existing Belle River 14

Peakers as a proxy for the variable fuel costs. The Belle River Peaker forecast 15

includes the Henry Hub price as well as the basis differential between Henry Hub 16

and the Belle River Peakers. In addition, the Company expects to enter into firm 17

transportation and storage agreements that require fixed costs that contribute to the 18

total delivered cost. These adders to the Henry Hub price – consisting of the basis 19

differential and firm transportation costs – average $0.30/MMBtu, which is shown in 20

Witness Mikulan’s Exhibit A-12, page 1, column (h). The Company believes that 21

these estimates more accurately reflect the avoided cost of gas transportation. 22

23

Q. On page 3, lines 13-15, ELPC Witness Jester states that the “EIA’s forecasted 24

natural gas delivered prices for the North Central region best captures the 25

379



natural gas costs an electric power plant in Michigan would incur for the 1

purposes of fueling electricity generation resources.” Do you agree? 2

A. No. As I described previously, gas transportation costs depend heavily on the 3

location of the generating plant. While the East North Central region does include 4

Michigan, it also includes Wisconsin, Illinois, Indiana, and Ohio. Each of these areas 5

have unique gas markets and local constraints that drive differences in delivered gas 6

pricing. For example, average natural gas pricing in February 2017 at Lebanon, OH, 7

was $2.69/MMBtu, at Chicago citygates was $2.81/MMBtu, at MichCon citygate 8

was $2.84/MMBtu, and at Dawn was $2.98/MMBtu. The average price at these gas 9

hubs in the same region differed by as much as $0.29/MMBtu during that month. 10

Therefore, it is most accurate and most reasonable to capture the avoided 11

transportation costs related to DTE Electric’s actual proposed generation plant on 12

which the Company’s avoided cost should be based. 13

14

Q. Does this complete your testimony? 15

A. Yes, it does. 16

380

381

1 MR. CHRISTINIDIS: Thank you, your Honor.

2 Moving on, the Company is sponsoring the reopened direct

3 testimony of Laura K. Mikulan, which consists of a cover

4 sheet and nine pages of questions and answers.

5 Accompanying her reopened direct testimony are nine

6 exhibits that have been designated as A-10, a one-page

7 exhibit; A-11, a two-page exhibit; A-12, a two-page

8 exhibit; A-13, a two-page exhibit; A-14, a three-page

9 exhibit; A-15, a one-page exhibit; A-16, also a one-page

10 exhibit; A-17, a two-page exhibit; and finally, A-18, a

11 two-page exhibit. Ms. Mikulan also sponsors reopened

12 rebuttal testimony, consisting of a cover sheet and five

13 pages of questions and answers. With that, your Honor,

14 the Company would move to bind into the record the

15 reopened direct testimony and reopened rebuttal testimony

16 of Ms. Mikulan, and move the admission of Exhibits A-10

17 through A-18.

18 JUDGE SNIDER: Based on the stipulation

19 of the parties, the reopened direct testimony and

20 reopened rebuttal testimony of Ms. Mikulan is admitted to

21 the record; Exhibits A-10 through A-18 are admitted.


23 - - -

24

25


STATE OF MICHIGAN



REOPENED

DIRECT TESTIMONY

OF

LAURA K. MIKULAN

382

DTE ELECTRIC COMPANY REOPENED DIRECT TESTIMONY OF LAURA K. MIKULAN

Line No.

LKM Reopened - 1

Q. Will you please state your name, business address and by whom are you 1

employed? 2

A. My name is Laura K. Mikulan. My business address is: One Energy Plaza, Detroit, 3

Michigan 48226. I am employed by DTE Electric Company (DTE Electric or 4

Company) within Integrated Resource Planning (IRP) as a Supervisor Professional. 5

6

Q. On whose behalf are you testifying? 7

A. I am testifying on behalf of DTE Electric. 8

9

Q. Are you the same Laura K. Mikulan who previously filed direct and rebuttal 10

testimony and exhibits in this proceeding? 11

A. Yes. 12

13

Q. What is the purpose of your testimony? 14

A. The purpose of my testimony is to submit the most reasonable inputs to the Staff 15

hybrid proxy methodology and discuss the impacts of various inputs as directed by 16

the Michigan Public Service Commission in its July 31, 2017 order (Order) in this 17

proceeding. I do not agree, however, that the Staff’s hybrid proxy methodology 18

results in DTE Electric’s avoided costs. I continue to believe that the Company’s 19

Natural Gas Combined Cycle (NGCC), which can also be referred to as a 20

Combined Cycle Gas Turbine (CCGT), that it has proposed in MPSC Case No. U-21

18419 is the Company’s avoided cost and the Company reserves all of its rehearing 22

and appellate rights. 23

24

383

L. K. MIKULAN Line U-18091 No.

LKM Reopened - 2

Q. Are you sponsoring any exhibits? 1

A. Yes. I am sponsoring the following exhibits: 2


A-10 Inputs for Staff’s Hybrid Proxy Plant Avoided Cost Calculation 4

A-11 Capacity and ICE Calculations 5

A-12 NGCC levelized variable cost 6

A-13 Levelized LMP Forecast 7

A-14 EIA Cost and Performance Characteristics of New Generating 8

Technologies, Annual Energy Outlook 2017 9

A-15 NGCC Heat Rate and Capacity Factor 10

A-16 Proposed Project Capital Cost 11

A-17 Fixed Charge Rate Calculation 12

A-18 Avoided Cost by Technology 13

14

Q. Were these exhibits prepared by you or under your direction? 15

A. Yes, they were. 16

17

Q. What are the Company’s inputs for calculating avoided costs per the Michigan 18

Public Commission Staff’s (Staff) “hybrid proxy plant method” as required 19

pursuant to the Order on page 25? 20

A. The Company recently filed a Certificate of Necessity (CON) application in Case 21

U-18419 for a new approximate 1,100 MW 2x1 Advanced Class combined cycle 22

gas turbine (NGCC). As part of that case, the Company obtained technology bids 23

and Engineer, Procure, and Construct bids, and based the CON application on the 24

values obtained for both cost and operating characteristics of the technology. See 25

384


LKM Reopened - 3

Exhibits A-10 and A-16. The Company also performed extensive dispatch 1

modeling using these operating characteristics to obtain the forecasted lifetime 2

capacity factor and average lifetime heat rate for the approximately 1,100 MW 3

NGCC unit. For the NGCC in this case, the Company is relying exclusively on its 4

inputs gathered for the CON filing. For the combustion turbine (CT) technology, 5

we do not have recent responses to request for proposal (RFP) bids for CT units, 6

because it is not our recommended technology in the IRP/CON. Instead, we are 7

relying on the recent 2017 Energy Information Administration (EIA) assumptions 8

from Table 8.2 and 8.3, issued January, 2017, as shown in Exhibit A-14. 9

10

Q. How do the 2017 EIA assumptions for NGCC compare to the DTE 2017 11

IRP/CON assumptions for NGCC? 12

A. 13

Table 1: 2017 EIA NGCC vs. DTE NGCC Operating Characteristics 14

2017 EIA NGCC 2017 DTE CON filing

NGCC

Size (MW) 429 1,150

Cost ($/kW) 1,085 860

Heat Rate (Btu/kWh) 6,300 6,374

Fixed O&M ($/kW-yr) 9.94 7.972

Variable O&M ($/MWH) 1.99 2.47

15

The 2017 EIA assumptions as shown in Exhibit A-14 are for a 429 MW NGCC, 16

which is significantly smaller than the DTE Electric approximately 1,100 MW 17

NGCC. Because of the smaller size, the EIA cost ($/kW) is higher than DTE 18

Electric’s cost due to economy of scale benefits for the Company ($1,085 for EIA 19

385


LKM Reopened - 4

vs. $860 for DTE Electric). The EIA heat rate of 6,300 Btu/kWh, and the fixed and 1

variable O&M combined, are all very comparable to the Company’s NGCC 2

operating characteristics. 3

4

Q. Can you please explain the details of Exhibit A-10 “Inputs for Avoided Cost 5

Calculation”? 6

A. Yes. As explained above, for the NGCC, the capital cost, capacity, and fixed O&M 7

are the same as the Company’s recent CON filing in case U-18419 which occurred 8

on the same day as the Order issued in this proceeding. These inputs and the many 9

others I describe below are the most reasonable because they come from real 10

estimates DTE Electric will rely upon for a real proposed NGCC generation plant 11

DTE Electric has proposed to construct and requested a Certificate of Necessity for 12

in MPSC Case No. U-18419. The Heat Rate and capacity factor are results from 13

modeling the specified NGCC in the CON filing using operational characteristic 14

data obtained for that filing along with the DTE Electric forecasted gas and power 15

prices. The gas price forecast shown in Exhibit A-12, page 1, column (i) and 16

energy price forecast (shown in Exhibit A-13) are the same as filed in the CON case 17

U-18419. The levelized fuel price forecast was obtained by using forward Henry 18

hub price for the years 2017 to 2022 and the Pace Global fundamental forecast 19

starting in year 2025 (Exhibit A-13, page 1 and 2). Pace Global is an energy 20

consultant, and a Siemens business. The years 2023 and 2024 are transition years 21

and are obtained by interpolating between 2022 and 2025. The Fixed Charge rate 22

of 11.8% shown in Exhibit A-10, column (c), line (8) was calculated using the 23

inputs for the NGCC unit in the CON filing, as shown in Exhibit A-17, page 1. 24

25

386


LKM Reopened - 5

Q. How did you determine the Heat Rate for the NGCC? 1

A. The Heat Rate of 6,374 Btu/kWh shown in Exhibit A-10, column (c), line (3), was 2

determined by using the operational characteristics of a NGCC unit received in a 3

RFP bid as inputs to the company’s PROMOD model and averaging the modeling 4

output over the years 2023 to 2040. These inputs included seasonal variations, start 5

up fuel, and heat rate degradation projections over the 18 years considered. The 6

duct fired portion of the unit was modeled separately from the main NGCC in the 7

PROMOD Model. The heat rate was calculated by taking the total heat consumed 8

by the main NGCC and the duct fired portion and dividing it by the total energy 9

produced by the main NGCC and the duct fired portion on an annual basis. These 10

annual heat rates were then averaged to yield the resulting heat rate of 6,374 11

Btu/kWh, as show in Exhibit A-15, column (aa), line (9). 12

13

Q. How did you determine the Capacity Factor for the NGCC? 14

A. The Capacity Factor of 89.5% shown in Exhibit A-10, column (c), line (2), was 15

determined by using the operational characteristics of a NGCC unit received in a 16

RFP bid as inputs to the company’s PROMOD model and averaging the modeling 17

output over the years 2023 to 2040. These inputs included seasonal variations, and 18

capacity degradation projections over the 18 years considered. The duct fired 19

portion of the unit was modeled separately from the main NGCC in the PROMOD 20

Model. The capacity factor was calculated by taking the total energy produced by 21

the main NGCC and the duct fired portion and dividing it by the total energy 22

possible to be produced by the main NGCC and the duct fired portion on an annual 23

basis. These annual capacity factors were then averaged to yield the resulting heat 24

rate of 89.5%, as shown in Exhibit A-15, column (aa), line (6). 25

387


LKM Reopened - 6

Q. Can you please explain the details of Exhibit A-11, page 1 “Capacity 1

Calculation”? 2

A. Yes. This exhibit follows the methodology established by Michigan Public Service 3

Commission Staff (Staff) Witness Jesse Harlow. The DTEE calculated CONE 4

value or capacity value of $95,715/MW-yr or $7.98/kW-month (column C, lines 19 5

and 20, respectively), is lower than the Staff value of $105,209/MW-yr or 6

$8.77/kW-month (shown in case U-18090, Exhibit S-11 page 1) since the Company 7

used a more up to date forecast from the same source utilized by Staff. DTE 8

Electric’s fixed charge rate is also lower. This capacity value is shown in the tariff 9

presented by Company Witness Mr. Bloch, on Exhibit A-19, as the Proxy Capacity 10

Rate. 11

12

Q. Can you please explain the details of Exhibit A-11, page 2 “ICE Calculation”? 13

A. Yes. This exhibit follows the methodology established by Staff Witness Harlow. 14

The capacity cost of a NGCC is calculated so it can be compared to the capacity 15

cost of a CT and the entire fixed cost difference between the CT and the NGCC is 16

then spread out over the energy produced by the avoided NGCC to determine the 17

ICE value or “Investment Cost Attributable to Energy” required by Staff’s 18

methodology. The capacity factor of the NGCC unit is required in the calculation. 19

The Company’s projected capacity factor for the NGCC is 89.5% (column (c), line 20

4). This value was determined by modeling the proposed NGCC in the PROMOD 21

dispatch model using the fuel and LMP prices presented in Exhibits A-12 and A-13, 22

as described above. The annual capacity cost of a NGCC is $122,080 (column (c), 23

line 22) for a resulting ICE value of $3.36/MWH (column (c), line 26). 24

25

388


LKM Reopened - 7

Q. Can you please explain the details of Exhibit A-12, page 1 “NGCC Variable 1

cost”? 2

A. Yes. This Exhibit is used to calculate the NGCC yearly variable cost. The 3

Company started with the Henry Hub forecasted Gas price, which is a combination 4

of Forwards and Fundamental price forecasts as previously explained. Then an 5

adder for gas delivery to burner tip is applied. The determination of this adder on 6

an annual basis is shown in Exhibit A-12, page 1, column (h). The adder includes 7

all costs associated with transportation, storage, lateral, compression, and basis for 8

the gas. The adder was determined by DTE Electric Fuel Supply and is the same as 9

was used in the recent CON filing for Case U-18419. The NGCC Heat Rate of 10

6,374 Btu/kWh was used. The NGCC Heat Rate was obtained by modeling the 11

proposed NGCC operational characteristics in the PROMOD model, as described 12

above. This heat rate value includes all start up fuel and projected lifetime heat rate 13

degradation. The DTE Electric value of 6,374 Btu/kWh is comparable to the 2017 14

EIA value of 6,300 Btu/kWh shown in Exhibit A-14 for “Adv Gas/Oil Comb 15

Cycle.” The NGCC variable O&M cost was $2.47/MWH as filed in the recent 16

CON filing. This value was then escalated by the DTE Electric assumed escalation 17

rate (shown in Exhibit A-12, page 1, Columns (m) and (n) that is the basis of the 18

2017 Fundamental forecast as presented in the 2017 IRP/CON. It is based on the 19

DTE Electric CPI forecast and averages 2.5% each year. 20

21

Q. Can you explain the details of Exhibit A-12, page 2? 22

A. Yes. The Exhibit shows the NGCC Levelized variable cost, based on the NGCC 23

variable cost from Exhibit A-12, page 1 and the ICE value from Exhibit A-11, page 24

2. The levelized value was determined using the DTE Electric pre-tax average 25

389


LKM Reopened - 8

weighted cost of capital of 7.98% from its most recent general rate case, Case No. 1

U-18014, for the four contract lengths. The weighted average cost of capital 2

calculation is shown in Exhibit A-17, page 2. These calculations were all done in 3

nominal dollars. These values were then used in the tariff calculations presented by 4

Witness Bloch on Exhibit A-19. 5

6

Q. Can you explain the details of Exhibit A-13, pages 1 and 2? 7

A. Yes. The exhibit shows the LMP monthly forecast data for both on and off peak 8

Energy Market prices. Years 2017 to 2022 came from the May 10, 2017 forwards 9

obtained from the Intercontinental Exchange ICE). Years 2025 to 2040 came from 10

the 2017 Reference scenario as modeled by Pace Global used in DTE Electric’s 11

CON application. Years 2023 and 2024 are transition years and are an interpolation 12

between years 2022 and 2025. On page 2, the values are levelized for the four 13

contract lengths and used in the tariff calculations presented by Witness Bloch on 14

Exhibit A-19. 15

16

Q. Can you explain the details of Exhibit A-18, pages 1 and 2? 17

A. Yes. Witness Bloch asked me to prepare a comparison of the avoided cost by 18

Technology using DTEE proposed method for avoided cost and the staff’s hybrid 19

proxy plant methodology assuming a ten-year contract. The Hybrid Proxy plant 20

method is shown in Exhibit A-18, page 1. Lines 1 to 5 show the calculation using 21

DTEE inputs from this re-opened filing. Lines 6 to 10 show the calculation using 22

the Staff’s most recent inputs as obtained from Case U-18090, August 11, 2017 23

filing. 24

25

390


LKM Reopened - 9

Page 2 of Exhibit A-18, shows the calculations for the DTEE proposed method with 1

DTEE’s inputs from this re-opened filing in columns (a) to (h). Column (i) and (j) 2

are the results from the hybrid proxy plant calculation assuming the forecasted LMP 3

price for a 10-year contract from page 1 as described above. Columns (k) and (l) 4

show the delta comparison between DTEE’s proposed method and the hybrid proxy 5

plant method using DTEE’s inputs and Staff’s most recent inputs respectively. 6

7

Q. Does this complete your reopened direct testimony? 8

A. Yes, it does. 9

391

STATE OF MICHIGAN




OF

LAURA K. MIKULAN

392

DTE ELECTRIC COMPANY REOPENED REBUTTAL TESTIMONY OF LAURA K. MIKULAN

Line No.

LKM Reopened Rebuttal - 1

Q. What is your name, business address and by whom are you employed? 1

A. My name is Laura K. Mikulan. My business address is: One Energy Plaza, Detroit, 2

Michigan 48226. I am employed by DTE Electric Company (DTE Electric or 3

Company) within Integrated Resource Planning (IRP) as a Supervisor Professional. 4

5

Q. Did you file direct testimony in this proceeding on behalf of DTE Electric 6

Company (DTE Electric or Company)? 7

A. Yes, I did. 8

9

Q. What is the purpose of your rebuttal testimony? 10

A. The purpose of my rebuttal testimony is to: 11

1) Question why Staff Witness Mr. Harlow did not utilize the latest Energy 12

Information Agency’s (EIA) forecasted Combustion Turbine (CT) cost to 13

calculate the capacity component of the Staff’s Method. 14

2) Rebut Witness Harlow’s utilization of the CMS LMP forecast as opposed to 15

DTE’s LMP forecast for use in developing the energy component of Staff’s 16

method for use as DTE’s avoided cost. 17

3) Rebut the Staff’s calculation of the Incremental Cost Attributable to Energy (ICE) 18

4) Rebut the Staff’s use of forecasted natural gas prices for the energy component 19

of Staff’s method. 20

21

Q. Are you sponsoring any rebuttal exhibits? 22

A. No, I am not. 23

24

393



Q. What EIA forecast of CT capital cost did Staff Witness Harlow utilize to 1

calculate the capacity component of Staff’s method? 2

A. Witness Harlow used cost data that was prepared by an engineering consultant for 3

the 2013 EIA Annual Energy Outlook (AEO) study. 4

5

Q. Do you agree with the use of that study? 6

A. No. More current information is available from the most recent 2017 EIA AEO 7

study. The EIA commissioned an engineering consultant to update technology costs 8

for CT, amongst other technologies, in 2016. While I disagree with the Staff’s 9

methodology, since updated numbers from the same source, EIA, are available it 10

would make sense for Staff to use those more recent 2016 values rather than stale 11

2013 estimates. Since Witness Harlow used the 2017 EIA AEO study for purposes 12

of his natural gas forecast in his reopened direct testimony (missing page numbers) 13

and Exhibit S-8.1, page 2, he was obviously aware of its existence. 14

15

Q. What forecast of LMP is Witness Harlow utilizing in developing the energy 16

component of Staff’s method for use as DTE’s avoided cost? 17

A. Witness Harlow utilized a LMP forecast that was derived from the Consumers 18

Energy Company’s ten year LMP projection in Case No. U-18090 (reopened direct 19

testimony). To determine 15 and 20 year LMPs, Staff then extrapolated those values 20

using an EIA gas forecast. 21

22

Q. Do you agree with the Staff method for use as DTE Electric’s avoided energy 23

costs? 24

394



A. No. I have provided an LMP forecast covering the entire 20-year timeline for 1

proposed contracts in Exhibit No. A-13. As I explained in my reopened direct 2

testimony on page 8, years 2017 to 2022 came from the May 10, 2017 forwards 3

obtained from the Intercontinental Exchange. Years 2025 to 2040 came from the 4

2017 Reference scenario as modeled by Pace Global used in DTE Electric’s CON 5

application Case U-18419. Years 2023 and 2024 are transition years and are an 6

interpolation between years 2022 and 2025. This forecast is superior to the Staff 7

method as it utilizes forward prices for the near term that represent the prices at which 8

people in the market are willing to transact. The outer years of the DTE Electric 9

forecast utilize a fundamental energy market model that contains a representation that 10

is consistent with the Company’s projected avoided cost Combined Cycle unit. 11

12

Q. Do you see other issues with Staff’s proposed forecast for LMPs? 13

A. Yes. 14

15

Q. Can you explain your concerns? 16

A. The Staff forecast for LMP and the forecast for natural gas utilized in Staff’s 17

forecasted variable costs for NGCC are inconsistent. As explained above, the LMP 18

forecast the Staff is proposing was derived from Consumers Energy which utilized 19

Consumers’ own natural gas price forecast. The Staff is then using the EIA natural 20

gas price forecast for their forecasted variable cost of NGCC. Allowing the PURPA 21

provider to select a forecasted price (LMP or variable cost of NGCC) that was 22

developed based on gas prices that are not consistent with each other will result in an 23

inaccurate representation of DTE’s avoided energy costs. 24

25

395



Q. Does your proposed forecast for LMPs suffer from this same flaw? 1

A. No. The Company has linked both choices for forecasted energy payments available 2

to PURPA providers (LMP or variable cost of NGCC) to a consistent forecast for 3

natural gas prices. Both the near term LMP and natural gas price forecast come from 4

forward market prices at the same point in time. The longer term natural gas price 5

and LMP forecast were derived by PACE from fundamental models that were linked 6

and developed utilizing a consistent market outlook. 7

8

Q. Do you think it is appropriate for the Consumer’s LMP forecast to be utilized 9

in determining DTE Electric’s avoided cost? 10

A. No. In addition to the inconsistencies explained above, I find the Staff’s proposal of 11

utilizing the Consumer’s LMP forecast for DTE Electric’s QF avoided cost to be 12

perplexing and inefficient. DTE Electric has not been able to properly vet the 13

accuracy of the Consumer’s forecast over the years and has little to no understanding 14

of the underlying assumptions. Furthermore, it appears that Consumer’s has again 15

updated their LMP forecast in their Second Reopened Rebuttal testimony filed in 16

Case U-18090 on August 21 (Exhibit A-46 (PDT-23)), which is different than the 17

Twenty Year LMP Projection filed by Staff in this case (U-18091) on August 15, 18

2017. DTE Electric avoided costs cannot be reliant upon the (apparently stale) 19

unknown assumptions and calculations of another utility. LMP forecasts for PURPA 20

QF contracts performed by Consumers Energy are not a reasonable basis to determine 21

DTE Electric’s avoided costs. 22

23

Q. What is DTE Electric’s opinion of Staff’s calculation of ICE? 24

396



A. DTE Electric is not in favor of the hybrid proxy method’s use of the ICE and doesn’t 1

believe that it accurately represents DTE Electric’s avoided costs going forward. ICE 2

assigns fixed cost arbitrarily to the variable energy component of the avoided cost 3

and in doing so could significantly over or under compensate for the total energy and 4

capacity value of the facility depending on its actual capacity factor. In addition, the 5

Staff-proposed hybrid method recommended three options for payment of the energy 6

component. The options are problematic because each energy option includes the ICE 7

adder which transfers some capacity costs to the resultant energy rate. This means 8

QFs would receive partial compensation for capacity costs in the energy payment 9

even during periods when capacity is not needed by DTE Electric. 10

11

Q. What is DTE Electric’s opinion regarding the use of forecasted natural gas 12

prices for the energy component of Staff’s method? 13

A. The energy component of the avoided cost should not be locked in over a lengthy 14

period given the historically volatile nature of the gas market. This would subject 15

DTE customers to potentially pay higher costs for energy than the Company’s actual 16

avoided cost over the applicable term of the contract. The energy payment should be 17

based on the actual - not forecasted avoided cost of energy and from the same avoided 18

unit that the QF receives capacity payment. 19

20

Q. Does this complete your reopened rebuttal testimony? 21

A. Yes, it does. 22

397

398

1 MR. CHRISTINIDIS: And with that, your

2 Honor, we can either proceed to Mr. Bloch, or if the

3 other parties wish to bind in their testimony. Typically

4 we like to have each party's testimony lined up in the

5 record, so --

6 JUDGE SNIDER: O.K. We'll have Mr. Bloch

7 go.

8 MR. CHRISTINIDIS: The Company would call

9 to the stand, your Honor, Timothy A. Bloch.

10 - - -

11 T I M O T H Y A. B L O C H

12 was called as a witness on behalf of DTE Electric Company

13 and, having been duly sworn to testify the truth, was

14 examined and testified as follows:

15 DIRECT EXAMINATION

16 BY MR. CHRISTINIDIS:

17 Q Can you please state your name and business address for

18 the record?

19 A Timothy Bloch, One Energy Plaza, Detroit, Michigan 48226.

20 Q And did you cause to be filed with the Commission a

21 document entitled reopened direct testimony of Timothy A.

22 Bloch, consisting of a cover sheet and eight pages of

23 questions and answers?

24 A Yes.

25 Q Do you have any changes to make to your reopened direct


399

1 testimony today on the stand?

2 A No.

3 Q Is that, then, the reopened direct testimony that you're

4 adopting today?

5 A Yes.

6 Q And you're also sponsoring one exhibit associated with

7 your reopened direct testimony, correct?

8 A Yes.

9 Q And it's correct that that one exhibit has been

10 designated as Exhibit A-19, consisting of four pages,

11 right?

12 A Yes.

13 Q Any changes to make that reopened direct exhibit?

14 A No.

15 Q Is that, then, the reopened direct exhibit you're

16 adopting today on the stand?

17 A Yes.

18 Q And are you also sponsoring reopened rebuttal testimony

19 in this case, consisting of a cover sheet and six pages

20 of questions and answers?

21 A Yes.

22 Q Any changes to make that reopened rebuttal testimony?

23 A No.

24 Q Is that, then, the rebuttal testimony you're adopting

25 today?


400

1 A Yes, it is.

2 Q And you're also sponsoring one exhibit associated with

3 that reopened rebuttal testimony designated as Exhibit

4 A-20, which is a one-page exhibit; that's correct, right?

5 A Yes.

6 Q Any changes to make to that rebuttal exhibit?

7 A No.

8 Q That, then, is the reopened rebuttal exhibit you're

9 adopting today on the stand, correct?

10 A Yes, it is.

11 MR. CHRISTINIDIS: With that, your Honor,

12 DTE Electric would move to bind into the record the

13 reopened direct and rebuttal testimonies of Mr. Timothy

14 A. Bloch, in lieu of the admission of Exhibits A-19 and

15 A-20, and tender Mr. Bloch for cross-examination by Ann

16 Arbor.

17 JUDGE SNIDER: All right. Is there any

18 objection to binding in the testimony or admission of the

19 exhibits?

20 MS. DURIAN: No, your Honor.

21 MS. NEWELL: No, your Honor.

22 JUDGE SNIDER: The reopened direct and

23 reopened rebuttal testimony are admitted and bound into

24 the record; Exhibits A-19 and A-20 are admitted.



STATE OF MICHIGAN



REOPENED

DIRECT TESTIMONY

OF

TIMOTHY A. BLOCH

401

DTE ELECTRIC COMPANY REOPENED DIRECT TESTIMONY OF TIMOTHY A. BLOCH

Line No.

TAB Reopened - 1

Q. Will you please state your name, business address and by whom are you 1

employed? 2

A. My name is Timothy A. Bloch. My business address is: One Energy Plaza, Detroit, 3

Michigan 48226. I am employed by DTE Energy Corporate Services, LLC within 4

Regulatory Affairs as Principal Financial Analyst. 5

6

Q. On whose behalf are you testifying? 7

A. I am testifying on behalf of DTE Electric Company (DTE Electric or Company) 8

formerly, The Detroit Edison Company (Detroit Edison). 9

10

Q. Did you file direct testimony in this proceeding on behalf of the DTE Electric 11

Company (DTE Electric or Company)? 12

A. Yes, I did. 13

14

Q. What is the purpose of your reopened testimony? 15

A. The purpose of my reopened testimony is to revise the Company’s proposed tariff 16

Rider No. 5, for Qualified Facilities (QF) 20MW and smaller that seek to sell their 17

electric output to the Company, to comply with changes directed by the Michigan 18

Public Service Commission (Commission) in its July 31, 2017 Order in this case. 19

In addition, I will discuss the Company’s position with respect to our true avoided 20

costs compared to the Michigan Public Commission Staff’s (Staff) “hybrid proxy 21

plant method”, and compare the costs between the two methods. 22

23

Q. Are you sponsoring any exhibits? 24

A. Yes. I am sponsoring the following exhibit: 25

402

T. A. BLOCH Line U-18091 No.

TAB Reopened - 2


A-19 Proposed Tariff Sheet - Standard Contract Rider No.5 2

3

Q. Was this exhibit prepared by you or under your direction? 4

A. Yes, it was. 5

6

Q. Will you please describe Exhibit A-19? 7

A. Exhibit A-19 contains the Company’s original proposed Standard Contract Rider 8

No. 5 titled “Small Power Production and Cogeneration Facilities 20MW and 9

Smaller” with redline markup to reflect the changes directed by the Michigan 10

Public Service Commission (Commission) in its July 31, 2017 Order. These 11

changes generally include: 12

1) Increasing the availability of the Standard Offer from 100 kW to 2MW 13

2) Utilizing Staff’s hybrid proxy model for calculating avoided costs using DTE 14

Electric’s proposed inputs. 15

3) Adding the requirement that the term of the Standard Offer must be 5, 10, 15, or 16

20 years. 17

4) Adding language to clarify that RECs generated by a QF project are owned by 18

the Customer. 19

In addition, due to the substantial 20-fold increase in the availability of the Standard 20

Offer from 100kW to 2MW, the Company requires an early termination provision 21

to the Standard Offer to help protect its ratepayers from overpaying as a result of 22

the Commission’s required changes to the Standard Offer. 23

24

403


TAB Reopened - 3

Q. Will you please describe the pricing under the Standard Offer Rate, (Section B 1

1)? 2

A. Yes. On page 13 of the Order, its states “The Commission agrees with the ALJ and 3

finds that the Staff’s hybrid proxy plant method is the most appropriate model for 4

calculating avoided costs pursuant to PURPA”. Toward that end, I used the format 5

developed by the Michigan Public Commission Staff (Staff) in their Exhibit S-1, 6

related to both energy sales and capacity sales. Energy sales consist of three pricing 7

options; 1) MISO real time locational marginal price (LMP); 2) LMP energy rate 8

forecast; or 3) proxy plant variable rate forecast. For capacity sales, the Proxy 9

Capacity Rate is based on a natural gas combustion turbine, as recommended by 10

Staff. Consistent with Exhibit S-1, the capacity payment rate will be adjusted by 11

the appropriate Effective Load Carrying Capability corresponding to the customer’s 12

specific QF technology. 13

14

Q. How were the energy and capacity rates derived as shown on your Exhibit A-15

19? 16

A. Pursuant to ordering paragraph A on page 25 of the Order, the Commission 17

required parties to file proposed inputs to be used for developing avoided capacity 18

cost using a natural gas combustion turbine (NGCT), also referred to as a 19

combustion turbine (CT) unit and avoided energy cost using a natural gas combined 20

cycle (NGCC), also referred to as a combined cycle gas turbine (CCGT), unit as 21

proxy plants and a calculation of investment cost attributable to energy. Company 22

Witness Ms. Mikulan provided me these amounts which come from real estimates 23

DTE Electric will rely upon for a real proposed CCGT generation plant DTE 24

Electric has proposed to construct and requested a Certificate of Necessity for in 25

404


TAB Reopened - 4

MPSC Case No. U- 18419. 1

2

Q. Will you please describe the pricing under the Non-Standard Offer Rate, 3

(Section B 2) of Exhibit A-19? 4

A. Yes. For energy sales, the pricing for the non-standard offer rate (QFs with 5

capacity between 2 MW and 20 MW), is the same as the standard offer rate subject 6

to negotiation between the Company and Customer consistent with 18 CFR 7

292.304(e). If the Company has a need for capacity over this same period, then 8

capacity pricing will be the same as the standard offer rate subject to negotiation 9

between the Company and Customer consistent with 18 CFR 292.304(e). 10

11

However, for capacity sales, if the Company indicates that it has no need for 12

capacity during the entire subsequent 10-year planning cycle, then the capacity shall 13

be the latest MISO prompt resource auction price. DTE Electric disagrees with this 14

requirement as first there must be a utility cost to be avoided. If no capacity is 15

needed, then no capacity is being avoided by DTE Electric and DTE Electric 16

ratepayers should pay $0 for capacity. Nevertheless, since the Commission has 17

clearly ordered otherwise, the Company has complied with the Commission’s 18

directive but reserves all of its rehearing and appellate rights. 19

20

Q. How have avoided costs been determined by the Commission in the past? 21

A. During the initial implementation of PURPA in Michigan, the Commission 22

approved a settlement agreement that defined the avoided costs for energy and 23

capacity as the costs associated with the utility’s next major generating unit under 24

construction. Since the 1980s the Company’s avoided costs were based on an 25

405


TAB Reopened - 5

actual Company generating asset. All existing PURPA contracts negotiated by the 1

Company during the 1980s and 1990s used the actual energy and capacity costs 2

associated with the Company’s Belle River Power Plant which was placed into 3

service in 1984. 4

5

Q. How has the Commission ordered avoided cost to be calculated in this 6

proceeding? 7

A. In the Commission’s July 31, 2017 order in this case, the Commission ordered the 8

use of the Staff recommended hybrid proxy plant method to calculate avoided costs. 9

This methodology bases capacity costs on a natural gas combustion turbine 10

(NGCT) and Staff’s hybrid proxy plant energy costs are based on the Customer’s 11

choice of NGCC variable costs, actual Locational Marginal Price (LMP), or an 12

LMP forecast. In addition, an investment cost attributable to energy (ICE) 13

payment, which is a capacity component to be paid by the Company to the 14

Customer as an energy rate adjustment factor is added to all energy payments and 15

represents the difference in the capacity costs between a NGCC and a NGCT. 16

17

Q. Do you believe abandoning the past practice of establishing avoided costs 18

based on the Company’s next major generating unit is reasonable? 19

A. No. It is particularly unreasonable considering the Company has recently (July 31, 20

2017 – the same day as the Commission reopened this proceeding) filed a 21

Certificate of Necessity (CON) requesting approval of a new NGCC baseload 22

facility in Case U-18419. To conclude that DTE Electric’s avoided costs could be 23

based on anything other than costs specific to the NGCC unit presented as the 24

proposed project and which is the Company’s next major generating unit is 25

406


TAB Reopened - 6

unreasonable. 1

2

Q. Has the Commission commented on the use of the Company’s new plant 3

proposal as a basis for determining DTE Electric’s avoided costs? 4

A. Yes. In its order remanding this case back to the parties, the Commission 5

acknowledges that “by the time of DTE Electric’s next biennial review, the CON 6

proceeding in Case No. U-18419 will have been completed, and the Commission 7

may have better information available on which to update the company’s avoided 8

costs.” This language indicates that the Commission recognizes that the preferred 9

method of determining avoided costs are those costs associated with a real plant 10

specific to the region in which the utility is located. Though the Company’s costs 11

filed in the CON are not currently incurred costs, they are based on real estimates 12

that the Company will rely upon and produce the best data in this case about the 13

costs that the Company would actually avoid by purchasing from QFs. 14

15

Q. Were the costs contained in the Company’s recent CON used for the 16

calculations provided by DTE Electric in the testimony and exhibits presented 17

in this case to date? 18

A. No. As the data was only recently filed on July 31, 2017, it was not used. 19

However, I have requested that Witness Mikulan present the Company’s actual 20

avoided costs for this remanded data input submittal based on the costs filed in case 21

U-18419 for the Company’s proposed NGCC unit. 22

23

Q. What are the outcomes using the Company’s real cost estimates and Staff’s 24

Hybrid proxy method and inputs? 25

407


TAB Reopened - 7

A. I asked Witness Mikulan to prepare a comparison of the avoided cost calculations 1

based on the DTE’s NGCC updated based on the CON, Staff’s proxy method using 2

DTE inputs and Staff’s proxy method using Staff inputs with 10 year LMP forecast. 3

The results are contained Exhibit A-18 and shown in the table below. 4

Type of Technology

DTE Method

DTE Inputs

Staff Method Hybrid proxy plant method (DTE inputs,

using Forecast

LMP)

Staff Method,

(Staff inputs, using

Forecast LMP)

Staff Method

less DTE method

Staff Method:

Staff Inputs (LMP) less

DTE method (NGCC)

($/MWH)

($/MWH)

($/MWH)

($/MWH)

($/MWH)

Hydro $47.83

$54.14

$68.58

$6.31

$20.76 Biomass $41.39

$48.96

$62.00

$7.57

$20.62

Landfill Gas $40.46

$48.22

$61.06

$7.75

$20.60 Solar $53.85

$58.98

$74.74

$5.13

$20.89

Wind $32.28

$41.64

$52.69

$9.36

$20.42

5

The results of this comparison indicate the Staff’s proxy method using DTE inputs 6

produce calculated avoided costs that are 10% to 29% higher than the Company’s 7

NGCC unit. Of even greater concern is that Staff’s proxy method using Staff’s 8

inputs produce calculated avoided costs that are 39% to 63% higher than the 9

Company’s NGCC. The Company’s avoided costs used in this comparison are 10

based on actual supportable estimates for constructing an NGCC and best represent 11

the Company’s avoided costs. 12

13

Q. Are there any specific examples or concerns you have with Staff’s inputs? 14

A. The Staff’s ICE adder which is based on the capacity cost difference between a 15

NGCC and NGCT has trended up with each filing made by Staff in this case and 16

the parallel PURPA case being conducted for Consumers Energy. The amount of 17

this arbitrary adder has nearly tripled since Staff’s initial filing. 18

408


TAB Reopened - 8

1 Filing Date Case No Staff ICE ($/kWh) Oct 27, 2016 U-18090 0.00257 Dec 2, 2016 U-18090 0.00475 Dec 1, 2016 U-18091 0.00378 Jun 12, 2017 U-18090 0.00874 Aug 11, 2017 U-18090 0.00768

2

Q. Does this complete your re-opened direct testimony? 3

A. Yes, it does. 4

409

STATE OF MICHIGAN




OF

TIMOTHY A. BLOCH

410

DTE ELECTRIC COMPANY REOPENED REBUTTAL TESTIMONY OF TIMOTHY A. BLOCH

Line No.

TAB Reopened Rebuttal - 1

Q. What is your name, business address and by whom are you employed? 1

A. My name is Timothy A. Bloch. My business address is: One Energy Plaza, Detroit, 2

Michigan 48226. I am employed by DTE Energy Corporate Services, LLC within 3

Regulatory Affairs as Principal Financial Analyst. 4

5

Q. Did you file reopened direct testimony in this proceeding on behalf of DTE 6

Electric Company (DTE Electric or Company)? 7

A. Yes, I did. 8

9

Q. What is the purpose of your reopened rebuttal testimony? 10

A. The purpose of my reopened rebuttal testimony is to show that Staff’s proposed 11

capacity and energy payments to Qualified Facilities (QF) are well in excess of DTE 12

Electric’s avoided costs of constructing a Natural Gas Combined Cycle (NGCC) 13

Plant as proposed in the Company’s current Certificate of Necessity (CON) Case No. 14

U-18419. I am also recommending corrections to Staff’s proposed tariff and 15

additional tariff language changes regarding the determination of units of capacity. 16

17

Q. Are you sponsoring any rebuttal exhibits? 18

A. Yes, I am sponsoring the following exhibit: 19


A-20 Capacity and Energy Cost Comparison – Staff Proposed Standard 21

Offer Tariff versus DTE Natural Gas Combined Cycle Plant 22

23

Q. Was this exhibit prepared by you or under your direction? 24

A. Yes, it was. 25

411



Q. Can you please describe and explain Exhibit A-20? 1

A. Yes. This exhibit shows the total energy and capacity costs associated with 2

purchasing power from the various QF technologies for 20 years using Staff’s 3

proposed standard offer tariff compared to the total cost of energy and capacity 4

associated with DTE Electric’s proposed natural gas combined cycle (NGCC) plant 5

filed in the Company’s CON case. Columns (a) through (h) show the determinants 6

and resulting costs for the different technologies using the Staff’s proposed tariff. In 7

columns (i) through (k), lines 1-9, I show the energy and capacity costs of DTE 8

Electric’s proposed NGCC plant based on the Company’s filing in the CON Case. 9

Columns (l) and (m) show the increase in total costs of Staff’s proposed standard 10

offer tariff compared to a NGCC on a $/MWh and percentage basis respectively. On 11

lines 10 – 17, I show a similar comparison using Staff’s proposed capacity cost of a 12

NGCC in column (i). 13

14

Q. What is the purpose of this comparison? 15

A. There have been many positions presented in this case with respect to determining 16

the Company’s avoided cost. However, no party in this case is disputing PURPA 17

Sections 292.304 (a) (1)(ii) which states “rates for purchase shall be just and 18

reasonable to the electric consumer of the electric utility and in the public interest”, 19

and (2), which states: “Nothing in this subsection requires any electric utility to pay 20

more than the avoided costs for purchases”. My understanding is these PURPA 21

requirements must be observed by the Commission when setting utility rates for 22

purchasing energy and capacity from QFs. The Commission cannot lose sight of the 23

underlying principal requirement of setting purchase rates from QFs based on the 24

Company’s avoided cost. At the end of the day, avoided cost must be based on the 25

412



most likely type of plant to be built when the Company needs capacity. Today, as 1

indicated in the Company’s CON filing, this would be a NGCC plant. However, the 2

Commission has initially determined that Staff’s proposed hybrid proxy method, 3

which represents a fictitious plant with cost and performance characteristics that 4

could not actually be achieved, best represents DTE Electric’s avoided cost, even 5

considering the Company’s proposal to build a NGCC. The purpose of this exhibit 6

is to look beyond all the complex issues presented in this case and go to the bottom 7

line results to confirm whether the PURPA requirements stated above have been met. 8

That is, what would DTE Electric customers pay for energy and capacity purchases 9

from a QF under Staff’s proposed tariff compared to what DTE Electric customers 10

would otherwise pay for energy and capacity from the Company’s planned NGCC 11

plant? 12

13

Q. What are your conclusions regarding the cost comparisons shown in Exhibit A-14

20? 15

A. If Staff’s standard offer tariff resulted in avoided costs that were reasonably close to 16

DTE Electric’s planned NGCC, the Commission could reasonably decide, regardless 17

of the flawed methodology, on choosing Staff’s Standard Offer tariff. However, as 18

indicated in Exhibit A-20, columns (l) and (m), Staff’s standard offer tariff produces 19

substantially higher ratepayer costs for all QF technologies compared to DTE 20

Electric’s NGCC. In the case of solar, the increase is 65% over the NGCC based on 21

Staff’s Levelized Proxy Plant energy payment option and 70% based on Staff’s 20-22

year forecast LMP energy payment option.1 Significant cost increases also result 23

when using Staff’s proposed NGCC capacity costs as shown in lines 10-17. The 24

1 The comparison between the 20-year forecasted LMP option were not included in Exhibit A-20.

413



majority of the cost difference is in the energy rates shown in columns (g) and (j) of 1

Exhibit A-20. These differences are essentially due to differences in natural gas and 2

associated transportation cost assumptions, forecasting methods between Staff and 3

DTE Electric, and Staff’s proposed $6.13/MWh Incremental Cost Attributable to 4

Energy (ICE) payment as addressed by Company Witnesses Mikulan and Swiech. 5

Similar significant forecasting differences and concerns also occur when comparing 6

Staff and Company LMP forecasts. 7

8

Q. What are your recommendations regarding the cost comparisons shown in 9

Exhibit A-20? 10

A. I recommend that the Commission address the energy rate differences by setting the 11

energy rate based on actual energy costs of an NGCC and eliminate the various 12

energy rate options proposed by Staff. Setting energy rates based on actual costs is 13

consistent with the Company’s previous long term power purchase agreements with 14

QFs approved by the Commission. Using actual energy costs would eliminate the 15

forecasting risk to DTE Electric customers, best represents the Company’s actual 16

avoided energy cost, and has been successfully used in other long term agreements 17

with QF facilities approved by the Commission. However, although the Company 18

disagrees with Staff’s fixed energy rate approach, if the Commission is determined 19

to provide QFs with fixed energy rate options for up to 20 years, the Commission 20

should choose the Company’s proposed forecasted energy rates as supported by 21

Company Witnesses Mikulan and Swiech to reduce the forecasting risk to DTE 22

Electric customers. In addition, if the Commission chooses to provide long term 23

fixed energy rates to QFs, it should certainly consider adding a price reopener in the 24

standard offer tariff to address significant deviations from actual market conditions 25

414



to ensure DTE Electric customers do not pay above DTE Electric’s avoided cost. 1

2

Q. What corrections and other tariff language changes are you recommending to 3

Staff’s proposed tariff? 4

A. The standard tariff should be very clear on how the capacity payment is calculated. 5

Staff’s current proposed tariff states: “The seller shall receive a monthly capacity 6

payment based on the proxy capacity rate and the units of capacity that the MISO 7

determines the seller’s Qualifying Facility can supply”. Following this statement, 8

Staff’s tariff lists a Capacity Payment of $8.71/MW-Month. Without endorsing 9

Staff’s proposed tariff, I am recommending the following corrections and clarifying 10

changes to Staff’s proposed tariff: 11

1) The term “Capacity Payment” should be changed to “Proxy Capacity Rate” 12

consistent with their description of the capacity payment. 13

2) The indicated rate of “$8.71/MW-Month” should be changed to “$8.71/kW-14

Month” to correctly convert Staff Witness Harlow’s proposed capacity value of 15

$104,467/MW-Year. 16

3) The description “units of capacity that the MISO determines the seller’s 17

Qualifying Facility can supply” should be more definitive in regards to how it is 18

determined, when it applies, and who is responsible for determining the units of 19

capacity. I am recommending the following additional clarifying language be 20

added to the tariff: “The capacity value of the Qualifying Facility shall be 21

determined annually using MISO’s Resource Adequacy capacity accreditation 22

methodology, currently Unforced Capacity (UCAP), and timeline. Updated 23

capacity values shall become effective based on the MISO Planning Year, 24

currently June 1 through May 31. The Company will be responsible for 25

415



determining the annual capacity value for each QF facility under contract for 1

capacity payment.” 2

3

Q. Does this complete your rebuttal testimony? 4

A. Yes, it does. 5

416

417

1 JUDGE SNIDER: Ms. Newell.

2 MS. NEWELL: Thank you, your Honor.

3 CROSS-EXAMINATION

4 BY MS. NEWELL:

5 Q Good morning, Mr. Bloch.

6 A Good morning.

7 Q Are you aware that the Commission issued an order in this

8 matter on July 31, 2017?

9 A Yes, I am.

10 Q Are you familiar with that order?

11 A Yes.

12 Q O.K. Are you familiar with the provision within that

13 order which states on page 24, "The requirement that the

14 Standard Offer be available only to DTE Electric full-

15 service customers are outside the scope of this

16 proceeding."?

17 A Yes, I read that.

18 Q O.K. And you stated earlier that you filed reopened

19 direct testimony, and Exhibit A-19 was attached to that;

20 is that correct?

21 A Yes.

22 Q And that was filed on August 15, 2017?

23 A Yes.

24 Q O.K. Could you please go to page 1 of Exhibit A-19.

25 A Sorry. I'm there now.


418

1 Q O.K. No problem. And do you see at the top somewhere

2 there is a section entitled "Availability"?

3 A Yes.

4 Q O.K. Could you just reread the first two sentences of

5 that section.

6 A "Full service customers with on-site small power

7 production or cogeneration facilities 20 megawatts and

8 smaller that seek to sell electric output from their

9 facility to the Company may receive service under this

10 tariff. The rate is available only to customers who

11 obtaining qualifying facility (QF) status from the

12 Federal" Regulatory Energy -- excuse me -- "Federal

13 Energy Regulatory Commission."

14 Q What does DTE mean by the term full-service customer as

15 used in this provision?

16 A As we proposed it, it would be full-service retail

17 customers of DTE Electric.

18 Q And do you believe that this section is compliant with

19 the July 31, 2017, order in its statement regarding

20 full-service customers, that it was outside this

21 proceeding?

22 MR. CHRISTINIDIS: Your Honor, I'd make

23 an objection to the extent it requests a legal

24 conclusion.

25 JUDGE SNIDER: It does.


419

1 MS. NEWELL: All right.

2 JUDGE SNIDER: I'll sustain the

3 objection.

4 Q (By Ms. Newell): Does DTE believe this language

5 restricts the availability of the Standard Offer tariff

6 to only full-service customers of DTE?

7 A The tariff as written, yes.

8 Q Could you now read the final two sentences of that

9 provision under "Availability", starting with "Prior to

10 interconnection"?

11 A "Prior to interconnection, the customer shall provide a

12 copy of such notification to the Company. A Standard

13 Offer under this tariff is applicable to QF's with less

14 than or equal to 2 megawatts. A Non-Standard Offer under

15 this tariff is applicable to QF's between 2 megawatts and

16 20 megawatts."

17 Q Is it DTE's position that the Standard Contract Rider

18 No. 5 is the only way for a qualifying facility to obtain

19 a contract with DTE under PURPA?

20 A For the Company's customers, that would be true.

21 Q And what about for entities that are not the Company's

22 customers?

23 A What would be an example?

24 Q Well, let me ask another question actually. What other

25 means and under what other tariffs would a qualifying


420

1 facility obtain a PURPA-based contract with DTE if not

2 through this tariff?

3 A The reason I was -- I had made the statement that it

4 doesn't apply to a noncustomer of DTE is because this is

5 a tariff approved by the Commission, so it would apply to

6 our customers.

7 Q So if there was a -- O.K. Just let me review my notes a

8 moment, please.

9 So then a qualifying facility that is not

10 a customer, then, there is not a tariff that would be

11 applicable to them?

12 A That would not be an appropriate pathway, in my

13 opinion --

14 Q How --

15 A -- since they're not customers of the Company.

16 Q Would they obtain, then, just through a regular

17 contractual relationship with DTE?

18 A They could.

19 Q Is there another method that, besides a contract, that

20 I'm unaware of that they would pursue?

21 A No. I guess the comment I'd have is, you know, since the

22 early '80s when we implemented PURPA 78, I don't believe

23 the Company has ever had a request from a qualified

24 facility that was not a customer of ours. The

25 determination of whether or not we would contract, we'd


421

1 simply have to look at the PURPA regulations in play at

2 the time of the request, as well as the state regulations

3 in play at the time. We'd have to -- obviously we'd

4 probably first look to see if we have a need for capacity

5 and energy because there's no reason to proceed without

6 that. And then finally, obviously there would be

7 physical considerations that would be part of this in

8 terms of the proximity of that facility to serve into our

9 service territory and any concerns that might go along

10 with that.

11 MS. NEWELL: I have no further questions,

12 your Honor.

13 JUDGE SNIDER: Any questions by Staff?


15 JUDGE SNIDER: Mr. Christinidis, do you

16 have any redirect?

17 MR. CHRISTINIDIS: No redirect, your

18 Honor.

19 JUDGE SNIDER: All right. Mr. Bloch,

20 you're all done. Thank you.

21 THE WITNESS: Thank you.

22 (The witness was excused.)

23 - - -

24 JUDGE SNIDER: Anything else on behalf of

25 DTE Electric Company, Mr. Christinidis?


422

1 MR. CHRISTINIDIS: No, your Honor.

2 JUDGE SNIDER: Thank you. Let's move on

3 to Staff. Ms. Durian.

4 MS. DURIAN: Pursuant to stipulation of

5 the parties, Staff moves for the binding in of the

6 reopened direct testimony of Julie K. Baldwin, consisting

7 of five pages, and the admission of the sponsored Exhibit

8 S-7, consisting of three pages. Staff moves for the

9 binding in of the responsive testimony of Julie Baldwin,

10 consisting of three pages, and related -- and for the

11 admission of related Exhibits S-9, consisting of five

12 pages, and S-9.1, consisting of four pages.

13 Staff, pursuant to stipulation of the

14 parties, moves for the binding in of the direct testimony

15 of Jesse Harlow, consisting of three pages, and for the

16 admission of related Exhibits S-8, which is two pages;

17 S-8.1, which is three pages; S-8.2, which is one page;

18 S-8.3, which is two pages; and moves for the binding in

19 of the reopened responsive testimony of Jesse Harlow,

20 consisting of two pages; and the admission of the related

21 Exhibits S-10, which is two pages; S-10.1, which is three

22 pages; S-10.2, which is one page; and S-10.3, which is

23 one page.

24 Staff has no further witnesses or

25 exhibits.


423

1 JUDGE SNIDER: All right. Pursuant to

2 the stipulation between the parties, the reopened direct

3 testimony of Witness Harlow and the reopened responsive

4 testimony of Witness Harlow is admitted to the record,

5 along with -- is bound into the record. Exhibits S-8,

6 S-8.1, S-8.2, S-8.3, are admitted; Exhibits S-10, S-10.1,

7 S-10.2, S-10.3 will admitted.

8 And the reopened direct testimony of

9 Witness Baldwin and the responsive rebuttal testimony is

10 bound into the record; and Exhibits S-7, S-9, and S-9.1

11 are admitted to the record.


13 - - -

14

15

16

17

18

19

20

21

22

23

24

25


August 15, 2017

S T A T E OF M I C H I G A N


* * * *

In the matter, on the Commission's own )

motion, establishing the method and avoided )

cost calculation for DTE ELECTRIC ) Case No. U-18091

COMPANY to fully comply with the Public )

Utilities Policy Act of 1978, 16 USC 2601 et seq. )

__________________________________________)

QUALIFICATIONS AND DIRECT TESTIMONY OF

JULIE K. BALDWIN

MICHIGAN PUBLIC SERVICE COMMISSION

424

QUALIFICATIONS OF JULIE K BALDWIN

CASE NUMBER U-18091

PART I

1

Q. Please state your full name, business address and occupation. 1

A. My name is Julie K. Baldwin, and my business address is 7109 West Saginaw 2

Highway, Lansing, Michigan 48917. I am employed by the Michigan Public 3

Service Commission (MPSC) as the Manager of the Renewable Energy Section 4

(Section) of the Electric Reliability Division. 5

Q. Please describe your current responsibilities. 6

A. I became Manager of the Renewable Energy Section in December 2010. In 7

addition to myself, the Section presently includes a staff of four professionals: 8

two departmental analysts, an engineer and auditor. This Section was established 9

in direct response to passage of Michigan’s Clean, Renewable and Efficient 10

Energy Act of 2008 (2008 PA 295). In general, the Section provides Staff 11

oversight and input to the Commission regarding all of the Commission’s 12

regulatory responsibilities for renewable energy. 13

Q. Describe your educational and professional background. 14

A. I graduated from Michigan State University in June 1987 with a Bachelor of 15

Science Degree in Chemical Engineering. I was employed by TRC 16

Environmental Consultants in Los Angeles, California from February 1988 to 17

June 1989 and was involved in various air quality consulting projects. 18

In July, 1989, I began my employment with the Michigan Public Service 19

Commission as a Public Utilities Engineer working in the areas of Act 9 natural 20

gas contract pricing issues, natural gas and petroleum products pipeline 21

certificates of public convenience and necessity, and monthly natural gas 22

production reporting. I began working on electric and natural gas tariff 23

425


CASE NUMBER U-18091

PART I

2

administration in December 2002 and in October 2003 was transferred to the 1

Rates and Tariff Section. My tariff administration responsibilities included 2

reviewing all electric and natural gas tariff filings, reviewing Commission Orders 3

to determine whether tariff filings were necessary, reviewing rate books to see if 4

they met the requirements of U-6300 (Administrative Regulations Prescribing the 5

Filing Procedures for Rate Schedules, Rules and Regulations, Standard Forms and 6

Contracts by Electric, Water, Steam and Gas Utilities), and serving as case 7

coordinator for various ex parte electric and natural gas tariff-related cases filed 8

with the Commission. 9

In June 2005, I attended an Electric Utility Consultants, Inc. (EUCI) course titled 10

Introduction to Cost of Service Concepts and Techniques for Electric Utilities in 11

Denver, Colorado. Shortly after the course, I was temporarily assigned as 12

Executive Assistant to former Commission Chairman J. Peter Lark. I remained in 13

that position until May 2006. Next, I was assigned to what is now the Renewable 14

Energy Section of the Electric Reliability Division. I was the lead engineer for 15

matters pertaining to electric interconnections and net metering. My work 16

responsibilities included developing and assisting in implementing rules for the 17

2008 PA 295 net metering program and electric utility interconnection, serving as 18

case coordinator for net metering and electric utility interconnection formal 19

complaint cases, resolving informal net metering and electric utility 20

interconnection complaints and inquiries, and public education and outreach. 21

Additional responsibilities included reviewing rates impacting distributed 22

generation in utility rate cases, green pricing programs, and renewable energy 23

426


CASE NUMBER U-18091

PART I

3

contracts filed for approval with the Commission. During 2008 and 2009, I 1

served as the Commission’s representative and Secretary on the Wind Energy 2

Resource Zone Board established by the Commission pursuant to 2008 PA 295. 3

Q. Have you previously filed testimony in proceedings before the Commission? 4

A. Yes. During my work at the MPSC, I have filed testimony in the following cases: 5

• Case No. U-10546 (Act 9 natural gas contract pricing case)6

• Various Act 9 natural gas pipeline cases7

• Case No. U-14347 (Consumers Energy Electric Rate Case)8

• Case No. U-15244 (Detroit Edison Rate Case)9

• Case No. U-16191 (Consumers Energy Electric Rate Case)10

• Case No. U-16180 (Indiana and Michigan Power Rate Case)11

• Case No. U-16356 (Detroit Edison Renewable Energy Reconciliation Case)12

• Case No. U-16543 (Consumers Energy Amended Renewable Energy Plan Case)13

• Case No. U-16582 (Detroit Edison Amended Renewable Energy Plan Case)14

• Case No. U-16424-R (Wisconsin Electric 2011 PSCR-R)15

• Case No. U-16434-R (Detroit Edison 2011 PSCR-R)16

• Case No. U-17072 (WEPCo Renewable Energy Plan Case)17

• Case No. U-17562 (WEPCo Renewable Energy Plan Case)18

• Case No. U-17735 (Consumers Energy Rate Case)19

• Case No. U-17767 (DTE Electric Rate Case)20

• Case No. U-18061 (UMERC Merger & Acquisition Case)21

• Case No. U-18090 (Consumers Energy Avoided Cost Case)22

427


CASE NUMBER U-18091

PART I

4

• Case No. U-18091 (DTE Electric Avoided Cost Case) 1

• Case No. U-18089 (Alpena Avoided Cost Case)2

• Case No. U-18092 (Indiana Michigan Power Avoided Cost Case)3

• Case No. U-18093 (Northern States Power Avoided Cost Case)4

• Case No. U-18094 (UPPCo Avoided Cost Case)5

• Case No. U-18095 & U-18096 (WEPCo and UMERC Avoided Cost Case)6

• Case No. U-18322 (Consumers Energy Rate Case)7

• Case No. U-18392 (Consumers Energy PURPA Contract)8

428

REOPENED DIRECT TESTIMONY OF JULIE K BALDWIN

CASE NUMBER U-18091

PART II

5


A. The purpose of my testimony is to sponsor Staff’s proposed reopened standard 2

offer tariff with updates according to the July 31, 2017 order issued in this case. 3

Q. Are you filing any exhibits? 4

A. Yes. I am filing the following exhibit: 5

Exhibit S-7 (JKB-3) Staff’s Proposed Reopened Standard Offer Tariff 6

Q. What revisions have you made to Staff’s proposed standard offer tariff filed as 7

Exhibit S-1 in this case? 8

A. I have made the following changes: 9

1. Clarified that the maximum design size for the standard offer tariff is 2 MWac10

in the Availability paragraph and updated the tariff header on each page to 2 MW. 11

2. Updated the Fixed ICE value for Option 1 in the energy rate option table to12

$0.00613 per kWh according to Staff witness Jesse J. Harlow’s Exhibit S-8. 13

3. Updated the LMP energy rates under Option 2 according to Mr. Harlow’s14

Exhibit S-8.2. A 20-year option was added. 15

4. Proxy Plant Variable Rate Forecast (Option 3) was modified to include an16

annual (non-levelized) payment schedule. 17

5. Proxy Plant Variable Rate Forecast (Option 4) includes a 20-year option.18

6. The Term provision was updated to reflect the 20-year option.19

7. Revised the renewable energy credit (REC) provision to indicate that the RECs20

belong to the QF. 21

Q. Does this conclude your testimony? 22

A. Yes. 23

429

August 31, 2017



* * * *

In the matter, on the Commission's own motion, )

establishing the method and avoided cost )

calculation for DTE ELECTRIC COMPANY ) Case No. U-18091

to fully comply with the Public Utility )

Policies Act of 1978, 16 USC 2601 et seq. )

__________________________________________)

REOPENED RESPONSIVE TESTIMONY OF

JULIE K. BALDWIN


430

REOPENED RESPONSIVE TESTIMONY OF JULIE K. BALDWIN

CASE NUMBER U-18091

1

Q. Are you the same Julie Baldwin who filed direct testimony in this case? 1

A. Yes. 2

Q. What is the purpose of your responsive testimony? 3

A. The purpose of my responsive testimony is to provide Staff’s proposed revisions 4

to DTE Electric’s proposed Rider-5, filed as DTE Exhibit A-19, sponsored by 5

witness Timothy Bloch in his reopened direct testimony and provide revisions to 6

Staff’s proposed Rider 5 filed on August 11,2017 as Staff Exhibit S-7. 7

Q. Are you filing any exhibits? 8

A. Yes. I am filing two exhibits: 9

Staff Exhibit S-9: Staff’s Proposed Rider No. 5 (Based on DTE Exhibit A-19) 10

Staff Exhibit S-9.1: Staff’s Proposed Rider No. 5 (Applicable to Standard Offer 11

Projects Only) 12

Q. What is Standard Contract Rider No. 5? 13

A. Standard Contract Rider No. 5 is the Company’s Rider applicable to small power 14

production and cogeneration facilities 20 MW and smaller. The current version in 15

the DTE rate book and the DTE Exhibit A-19 includes Standard Offer, as well as 16

non-Standard Offer option. 17

Q. Why are you providing two versions of Standard Contract Rider No. 5 in this 18

case? 19

A. The July 31, 2017 order in this case left the issue open as to whether Rider 5 20

should apply only to the Standard Offer-sized projects or continue to be 21

applicable to all qualifying facilities up to 20 MW and, therefore, include both the 22

standard offer and non-standard offer terms. There are valid reasons for adopting 23

431


CASE NUMBER U-18091

2

either version of Rider 5 in this matter. Two factors in support of the Rider 5 1

version with only the Standard Offer included are (1) consistency with the 2

Standard Offer Tariff recently approved for Consumers Energy in Case No. U-3

18090, which does not contain non-Standard Offer terms, and (2) including only 4

Rider 5 terms and conditions specifically related to the Standard Offer reduces the 5

complexity of the tariff. 6

In contrast, reasons for supporting the Rider 5 version with 7

information about both the Standard Offer and non-Standard Offer are (1) DTE 8

has historically included information for both on a single tariff, (2) including both 9

Standard Offer and non-Standard Offer information could be helpful to 10

Qualifying Facilities (QFs) seeking both sets of information in one location. 11

Staff is providing both versions for consideration in this case because 12

either option may be equally valid for the Commission’s adoption. 13

Q. What changes to DTE Electric’s Exhibit A-19 are you presenting on Staff Exhibit 14

S-9? 15

A. The list of changes shown on Staff Exhibit S-9 are provided below: 16

Tariff size caps identified as AC 17

18

Updated energy rates and a 20-year, annual schedule of energy rates in the 19

energy rate option table, as supported byStaff witness Jesse J. Harlow 20

Exhibits S-10 through S-10.4. 21

22

Revised capacity payment language according to Environmental Law & 23

Policy Center, the Ecology Center, the Solar Energy Industries 24

Association, and Vote Solar (ELPC) witness Douglas B. Jester testimony 25

page 7, lines 2 – 13. 26

27

Revised solar ELCC to reflect MISO’s number according to Staff witness 28

Jesse J. Harlow’s testimony 29

432


CASE NUMBER U-18091

3

1

Revised wind ELCC to reflect MISO’s number according for consistency 2

with the solar ELCC and other ELCC numbers provided by the Company 3

4

Revised Early Termination Provision to apply only to capacity 5

Q. Are you including all of the above revised information on Staff Exhibit S-9.1, 6

the version of Rider 5 with only the Standard Offer provisions? 7

A. Yes. The Standard Offer on Exhibit S-9.0 has already been updated. 8

Q. Why are you recommending the capacity payment language provided by ELPC 9

witness Jester? 10

A. For planning purposes, providing certainty in the method used to calculate 11

capacity is helpful for both DTE and the QF. Providing certainty in the 12

calculation method, moreover, does not remove the incentive for the QF to 13

operate efficiently because capacity payments after the first summer of generation 14

are dependent on historical performance. 15

Q. Why are you recommending the Early Termination Provision change? 16

A. For Standard Offer sized projects, in the event of an early termination, it is not 17

appropriate to require a QF to pay for replacement energy for the remaining term 18

of the contract. The Company is required to demonstrate on an annual basis that 19

it has a certain level of capacity available which makes it reasonable that a QF 20

should have some contractual responsibility for replacement capacity. However, 21

there is a robust wholesale market for energy and, in all likelihood, DTE will be 22

able to call upon that market to obtain replacement energy. 23

Q. Does this conclude your testimony? 24

A. Yes. 25

433



* * * *

In the matter of the application of )

On the Commissions own motion, establishing )

the method and avoided cost calculation for ) Case No. U-18091

DTE Electric Company to fully comply )

with the Public Utilities Regulatory )

Policy Act of 1978, 16 USC 2601 et seq. )

__________________________________________)

QUALIFICATIONS AND DIRECT TESTIMONY OF

JESSE J. HARLOW


434

QUALIFICATIONS OF JESSE J. HARLOW

CASE NUMBER U-18091

PART I

Q. Please state your full name, business address and occupation. 1

A. My name is Jesse J. Harlow and my business address is 7109 West Saginaw, 2

Lansing, Michigan 48917. I am employed as a public utilities engineer in the 3

Renewable Energy Section of the Electric Reliability Division at the Michigan 4

Public Service Commission (MPSC or Commission). 5

Q. Please describe your educational background. 6

A. In 2005, I earned a Bachelors of Science in Engineering from Michigan State 7

University. Prior to my course work at Michigan State University, I was in an 8

engineering transfer program at Lansing Community College where I was a 9

member of the Phi Theta Kappa honor society. 10

Q. What is your professional work experience? 11

A. I have worked for the Commission since 2006. From 2006 until 2008, I worked 12

in the Energy Grants Section of the Motor Carrier, Energy Grants and Information 13

Division. My primary responsibility was for award selection and administration 14

of Michigan Energy Efficiency (MIEE) grants. MIEE grants made up 15

approximately 25% of the total allocations from the more than $80 million per 16

year Low-Income and Energy Efficiency Fund. 17

In the later part of 2008, I was transferred into the Renewable Energy 18

Section and became involved in the implementation of 2008 PA 295 (Act), 19

focusing on electric provider’s Renewable Energy Plan filings. 20

435


CASE NUMBER U-18091

PART I

Q. Have you had any other training that is relevant to your testimony? 1

A. Yes, In 2008 I attended the Institute of Public Utilities Regulatory Studies 2

Program, a two-week program with course work designed to educate regulatory 3

professionals. In 2009, I attended the Institute of Public Utilities Advanced 4

Regulatory Studies Program. In 2011, I attended courses in both the Institute of 5

Public Utilities Regulatory Studies Program and the Institute of Public Utilities 6

Advanced Regulatory Studies Program. Since then, I have continued to attend 7

various courses in both the Institute of Public Utilities Regulatory Studies 8

Program and the Institute of Public Utilities Advanced Regulatory Studies 9

Program. To stay abreast with the rapidly growing and evolving field of 10

renewable energy, I have attended and continue to attend various renewable 11

energy related seminars and conferences. I have also presented at a number of 12

events on renewable energy and 2008 PA 295 related issues. In November of 13

2016, I received training from the Mid-Continent Independent System Operator 14

(MISO) on the EGEAS Capacity Expansion Modeling Software. Additionally, in 15

May of 2017 EPIS provided Staff with a two week trial of and guidance on 16

Aurora Modeling Software. 17

Q. Have you filed testimony or rebuttal testimony in any other cases? 18

A. I have filed testimony and/or rebuttal testimony in the following cases: 19

U-16300 Consumers Energy Company’s 2009 Renewable Energy Reconciliation20

on transfer price; 21

U-16356 Detroit Edison Company’s 2009 Renewable Energy Reconciliation on22

transfer price; 23

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CASE NUMBER U-18091

PART I

U-16543 Consumers Energy Company’s Amended Renewable Energy Plan on 1

the Company’s transfer price and solar program; 2

U-16580 Alpena Power Company’s Biennial Renewable Energy Plan;3

U-16582 Detroit Edison Company’s Amended and Biennial Renewable Energy4

Plan on the Company’s transfer price and solar program; 5

U-16588 Wisconsin Electric Power Company’s Biennial Renewable Energy Plan6


U-16367 Wisconsin Electric Power Company’s 2010 Renewable Energy8

Reconciliation on transfer price; 9

U-16301 Consumers Energy Company’s 2010 Renewable Energy Reconciliation10

on the Company’s Pre-Act expenditures and transfer price; 11

U-16045-R Consumers Energy Company’s 2010 PSCR on transfer price;12

U-16581 Consumers Energy Company’s Biennial Renewable Energy Plan;13

U-16432-R Consumers Energy Company’s 2011 PSCR on transfer price;14

U-16662 Wisconsin Electric Power Company’s 2011 Renewable Energy Cost15


U-16655 Consumers Energy Company’s 2011 Renewable Energy Cost17


U-16656 Detroit Edison Company’s 2011 Renewable Energy Cost Reconciliation19


U-17302 DTE Electric Company’s Biennial Renewable Energy Plan;21

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CASE NUMBER U-18091

PART I

U-17301 Consumers Energy Company’s Biennial Renewable Energy Plan on 1

transfer price and solar program additions; 2



U-17322 Detroit Edison Company’s 2012 Renewable Energy Cost Reconciliation5




U-17633 Indiana Michigan Power Company’s 2013 Renewable Energy Cost9


U-17632 DTE Electric Company’s 2013 Renewable Energy Cost Reconciliation11


U-17752 Consumer Energy Company’s Amended Renewable Energy Plan13

regarding its Solar Gardens program; 14

U-17792 Consumers Energy Company’s 2015 Renewable Energy Plan with15

respect to the Company’s treatment of transfer price as is applies to Company-16

owned facilities; 17

U-17804 DTE Electric Company’s 2014 Renewable Energy Cost Reconciliation18


U-17805 Indiana Michigan Power Company’s 2014 Renewable Energy Cost20


438


CASE NUMBER U-18091

PART I

U-17809 Wisconsin Electric Power Company’s 2014 Renewable Energy Cost 1




U-18090 Consumers Energy Company’s Avoided Cost Case;5

U-18091 DTE Electric Company’s Avoided Cost Case;6

U-18092 Indiana Michigan Power Company’s Avoided Cost Case;7

U-18093 Northern States Power Company’s Avoided Cost Case;8

U-18094 Upper Peninsula Power Company’s Avoided Cost Case;9

U-18392 Consumers Energy Company’s application for approval of Amendment10

2 of Power Purchase Agreement with T.E.S. Filer City Station Limited 11

Partnership.12

439

REOPENED DIRECT TESTIMONY OF JESSE J. HARLOW

CASE NUMBER U-18091

PART II

Q. What is the purpose of your reopened testimony? 1

A. The purpose of my testimony is to file final, proposed avoided cost calculations 2

for DTE Electric Company (DTE Electric or Company) as directed by the July 3

31, 2017 Order re-opening this case. 4

Q. Are you sponsoring any Exhibits? 5

A. Yes. I am sponsoring the following Exhibits: 6

Exhibit S-8 (JJH-5) Pages 1-2, MPSC Staff’s Avoided Cost Methodology and 7

Calculation; 8

Exhibit S-8.1 (JJH-6) Pages 1-3, MPSC Staff’s Variable Natural Gas Combined 9

Cycle (NGCC) Plant Cost (Avoided Energy Cost); 10

Exhibit S-8.2 (JJH-7) Twenty Year LMP Projections. 11

Exhibit S-8.3 (JJH-8) Schedule of Annual Avoided Energy Cost Payments 12

STAFF’S MODIFIED PROXY PLANT METHODOLOGY 13

Q. Can you please provide a discussion of what has changed between now and the 14

December 1, 2016 exhibits with respect to Staff’s Modified Proxy Plant 15

Methodology? 16

A. In my December 1, 2016 testimony in this case, I presented Staff’s Proposed 17

Method as a basis model for calculating the Company’s avoided cost. The intent 18

was that this model would be used, combined with inputs the Commission 19

deemed appropriate, for calculating the Company’s avoided cost. For inputs, 20

Staff originally applied the Company’s numbers as presented in its Exhibits that 21

were filed on September 22, 2016. Pursuant to the July 31, 2017 Order in this 22

case, the Commission asked for the final proposed avoided cost calculations. The 23

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CASE NUMBER U-18091

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model has remained the same but Staff has since updated the inputs based on what 1

Staff believes is an appropriate avoided cost. 2

CAPACITY COMPONENT OF STAFF’S METHOD 3

Q. Would you explain the capacity component inputs to Staff’s methodology? 4

A. For capacity inputs, Staff utilized the capital, operations and maintenance, heat 5

rate, size and performance characteristics that the Mid-Continent Independent 6

Systems Operator (MISO) used for calculating the 2017/18 Planning Year Cost of 7

New Entry (CONE). The result is a capacity value of $104,467 per megawatt-8

year. 9

Q. If the same inputs that MISO uses to calculate CONE were used in Staff’s model, 10

then why is Staff’s capacity value approximately $10,000 higher than CONE? 11

A. Staff utilized the Company’s fixed charge rate of 11.5% for a Combustion 12

Turbine (CT) and a discount rate of 7.65% to provide a more Company specific 13

avoided cost rate. When calculating MISO’s CONE using a fixed charge rate 14

method it results in a fixed charge rate that is lower than 11.5%, resulting in a 15

lower overall cost. 16

Q. Can you explain where the MISO CONE calculation inputs came from? 17

A. In February of this year, Staff contacted MISO requesting a detailed explanation 18

of the inputs and methodology used to calculate CONE for the 2017/18 planning 19

year. On February 7, 2017, MISO arranged a conference call with a number of 20

Staff to walk through the calculation for planning year 2017/18. MISO explained 21

that the basis for the CT calculation comes from the Energy Information Agency’s 22

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CASE NUMBER U-18091

PART II

(EIA) Annual Energy Outlook, with certain assumption included for escalation 1

rate, debt and equity ratios, and locational cost variances (for Zone 7). 2

ENERGY COMPONENT OF STAFF’S METHOD 3

Q. Can you explain what has changed with respect to the third energy component 4

option (forecasted variable cost of an NGCC) between now and the December 1, 5

2016 Exhibits? 6

A. Staff calculates its Transfer Price based on the NGCC every spring and posts it in 7

the U-15800 Docket so that the electric providers have time to utilize the outputs 8

for renewable cost reconciliations. For purposes of this filing, Staff sees benefit 9

in filing the most recent NGCC variable cost data from the Transfer Price to 10

account for updated gas price forecasts from EIA the inputs from the Transfer 11

Price model. To provide a utility specific avoided cost, Staff again utilized the 12

Company’s discount rate and fixed charge rate for an NGCC of 11.5% to the 13

energy component. 14

Q. What is the benefit to using the Transfer Price inputs for establishing the energy 15

option based on an NGCC? 16

A. Staff sees benefit in using the Transfer Price inputs as they are from a nationally 17

recognized source (EIA) and utilize inputs that have been vetted through a 18

collaborative process (a Transfer Price stakeholder process and numerous 19

contested cases). In an effort to align the Transfer Price model with the avoided 20

energy cost component in this case, Staff made four revisions to the Transfer 21

Price model: 1) As mentioned above, Staff utilized the Company’s fixed charge 22

rate; 2) Staff calculated costs out to 2036 to provide a 20 year projection, as 23

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CASE NUMBER U-18091

PART II

opposed to stopping in 2029 with the Transfer Price calculation, 3) Staff utilized 1

the EIA real natural gas price forecast for reasons explained below, and 4) Staff 2

included a gas transportation cost for reasons explained below. 3

Q. Can you explain why Staff’s natural gas projection from EIA is different than 4

what was used for calculating the Transfer Price? 5

A. The natural gas price forecast used in Exhibit S-8.1 (JJH-6) utilizes the most 6

recent EIA data source from the 2017 Annual Energy Outlook (AEO) which 7

provides a real and nominal price forecast. To calculate the avoided energy cost 8

based on an NGCC, Staff utilized the real dollar price forecast inflated to 2017 9

dollars. 10

Q. Why did Staff utilize the real dollar natural gas forecast as opposed to the nominal 11

price forecast used in the Transfer Price? 12

A. The reasoning for this change is the nominal price forecast would be appropriate 13

if it were utilized on a net present value (NPV) basis only, but since Staff takes 14

the NPV of the gas forecast and applies a change rate based on Global Insight 15

indices that assume an inflation rate, the real price forecast is the most appropriate 16

for this purpose. 17

Q. Since the 2017 Staff Transfer Price utilizes the nominal natural gas price forecast, 18

does this mean that it is calculated incorrectly? 19

A. In hindsight, inputting the real gas price rather than the nominal gas price is a 20

more refined and accurate way for Staff to calculate the 2017 Transfer Price, but 21

the Transfer Price is only an allocation method for recovery of costs related to 22

renewable energy. The Transfer Price ultimately does not affect overall cost 23

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CASE NUMBER U-18091

PART II

recovery to the electric provider as it recovers all of the renewable cost through 1

either the regulatory liability funded via renewable surcharge revenue and the 2

Transfer Price through the power supply cost recovery (PSCR). 3

Q. Are you proposing an additional methodology to calculate the energy component 4

of the avoided cost? 5

A. I am proposing to offer the option of a simplified methodology, based on Staff’s 6

current method, for calculating the energy component of the avoided cost. This 7

methodology is shown in Exhibit S-8.3 (JJH-8). 8

Q. Why does Staff support this proposed methodology for calculating the energy 9

component of the avoided cost? 10

A. Staff supports this method as a means to address concerns regarding the 11

appropriate application of real and nominal gas price forecasts and discount rates, 12

as raised in the first reopened rebuttal testimony in the Consumers Energy 13

Company’s Avoided Cost Case No. U-18090. Staff still supports its original 14

methodology as filed in its testimony on December 1, 2016. This new option 15

offers a means to simplify the calculation, making a debate regarding using real or 16

nominal dollars unnecessary. 17

Q. What makes this proposed method simplified? 18

A. When combined with a nominal natural gas price forecast, gas transportation and 19

variable O&M, this methodology uses simple to understand calculations to 20

determine energy pricing in each year. 21

Q. You have included a gas transportation cost in your calculations. Why is it 22

appropriate to include a gas transportation cost? 23

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CASE NUMBER U-18091

PART II

A. As discussed in avoided cost technical work groups held with respect to Case No. 1

U-18090 mentioned above, gas transportation costs are real costs that the 2

Company must pay to transport natural gas from a hub location to the plant in 3

which it is to be used. To determine avoided energy cost, this cost should be 4

included when considering gas price forecasts at hub locations. 5

Q. What is the source of your gas transportation cost? 6

A. This gas transportation cost was provided by the Consumers Energy Company. It 7

represents the price to transport gas from the Henry Hub to Consumers Energy 8

Company’s proxy plant. Its basis is a levelized tariff rate which should be very 9

comparable to DTE Electric’s rate. 10

FIXED INVESTMENT COST ATTRIBATABLE TO ENERGY (ICE) 11

Q. What changes were made with respect to the fixed ICE component inputs to 12

Staff’s proposed method between now and the December 1, 2016 filing? 13

A. Since this calculation is simply the fixed cost component difference between an 14

NGCC and a CT, the above changes have also impacted the fixed ICE. 15

TWENTY YEAR LMP PROJECTION 16

Q. Can you explain your Exhibit 8.2 (JJH-7) Twenty Year LMP Projection? 17

A. Staff utilized the same LMP projection that was filed in the December 1, 2016 18

testimony. This was derived from the Consumers Energy Company’s ten year 19

LMP projection in Case No. U-18090. To determine 15 and 20 year LMPs, Staff 20

extrapolated these values using yearly percent changes for the natural gas forecast 21

contained in the EIA AEO 2017 for similar years. 22

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CASE NUMBER U-18091

PART II

STAFF’S MODIFIED PROXY PLANT METHODOLOGY COMPARISON TO 1

TRANFER PRICE 2

Q. Can you explain the similarities and differences between Staff’s Modified Proxy 3

Plant Methodology and the Transfer Price model? 4

A. The models are very similar but Staff feels that it is inappropriate to use the 5

Transfer Price for purposes of establishing avoided cost for the following reasons: 6

1) Staff opines that the Transfer Price was and is intended strictly to be used7

under the renewable cost recovery mechanism in 2008 Public Act 295 (PA 295) 8

to allocate costs between the PSCR and regulatory liability account; 2) PA 295 9

states that the lesser of the Transfer Price or actual costs shall be used for cost 10

recovery and Staff has taken the position, and the Commission has agreed, that 11

this should apply to power purchase agreements and Company-owned facilities, 12

so the Transfer Price essentially acts as a cap for PSCR recovery of renewable 13

costs; and 3) Staff opines that the avoided cost methodology should clearly 14

distinguish between a capacity and energy component so that the appropriate 15

effective load carrying capacity can be applied to the capacity component, which 16

Staff’s Modified Proxy Plant Methodology does. 17

Q. Staff’s Modified Proxy Plant Methodology does not include a change rate for the 18

capacity or fixed ICE component, while the Transfer Price model includes a 19

change rate utilizing Global Insight indices. Why is this appropriate? 20

A. The Transfer Price represents the levelized cost of a new NGCC plant being built 21

in each year. As mentioned above, this is to establish a cap for recovery of 22

renewable revenue requirements through the PSCR. Electric providers are 23

446


CASE NUMBER U-18091

PART II

required to recover the lesser of the Transfer Price or actual costs through the 1

PSCR while any remaining costs are recovered through the regulatory liability 2

account. For avoided cost purposes, the rate would be based on the avoided cost 3

of capacity at the time the contract is implemented and not subject to a change 4

rate or escalation rate. Nevertheless, the energy component, based on an NGCC 5

provided in Exhibit S-8.1 (JJH-6), is calculated using the same change rate as the 6

2017 Staff Transfer Price model utilizing Global Insight indices although a real 7

natural gas price forecast is used. 8

Q. Does this complete your direct testimony? 9

A. Yes it does. 10

447

8/31/2017

S T A T E O F M I C H I G A N


* * * *

In the matter of the application of )

On the Commissions own motion, establishing )

the method and avoided cost calculation for ) Case No. U-18091

DTE Electric Company to fully comply )

with the Public Utilities Regulatory )

Policy Act of 1978, 16 USC 2601 et seq. )

__________________________________________)

REOPENED RESPONSIVE TESTIMONY OF

JESSE J. HARLOW


448

REOPENED RESPONSIVE TESTIMONY OF JESSE J. HARLOW

CASE NUMBER U-18091

8/31/2017

Q. What is the purpose of your reopened responsive testimony? 1

A. The purpose of my testimony is to update the final, proposed avoided cost 2

calculations for DTE Electric Company (DTE Electric or Company) to reflect the 3

Company’s current weighted average cost of capital (WACC) and fixed charge 4

rate. I am also suggesting use of a zonal resource credit (ZRC) basis for the 5

capacity component to be consistent with the Consumers Energy Company 6

Avoided Cost filing in Case No. U-18090. 7

Q. Are you sponsoring any Exhibits? 8

A. Yes. I am sponsoring the following exhibits similar to my previous exhibits with 9

changes highlighted in yellow reflecting the updated fixed charge rate, WACC 10

and ZRC capacity: 11

Exhibit S-10 (JJH-9) Pages 1-2, MPSC Staff’s Avoided Cost Methodology and 12

Calculation; 13

Exhibit S-10.1 (JJH-10) Pages 1-3, MPSC Staff’s Variable Natural Gas Combined 14

Cycle (NGCC) Plant Cost (Avoided Energy Cost); 15

Exhibit S-10.2 (JJH-11) Twenty Year LMP Projections. 16

Exhibit S-10.3 (JJH-12) Schedule of Annual Avoided Energy Cost Payments. 17

Q. Can you explain what has changed with respect to your exhibits between now and 18

your filing on August 15, 2017? 19

A. I have updated all exhibits using a fixed charge rate of 11.8% up from 11.5%. I 20

have also updated the discount rate using 7.98% up from 7.65%. These changes 21

are consistent with what the Company filed in its August 15, 2017 testimony. All 22

of the changes in my exhibits have been identified with yellow highlighting. 23

449

REOPENED RESPONSIVE TESTIMONY OF JESSE J. HARLOW

CASE NUMBER U-18091

8/31/2017

Q. On Exhibit S-10 (JJH-9) you have included a capacity price on a ZRC basis. Can 1

you explain your justification for this? 2

A. A ZRC basis accounts for how the Midcontinent Independent System Operator 3

(MISO) values units of capacity. A ZRC takes into account the Effective Forced 4

Outage Rate (EFORd) and the Derate, or Effective Load Carrying Capacity 5

(ELCC) for intermittent resources, to determine a generating unit’s contribution to 6

capacity on peak. The Commission has determined in Consumers Energy 7

Company’s Avoided Cost Case No. U-18090 that the ZRC basis is the appropriate 8

means to value capacity and Staff suggests that this be consistent between utilities 9

that are subject to the MISO market for resource planning. 10

Q. Can you explain how this $/ZRC-year capacity value is derived? 11

A. Staff calculated the $/ZRC-year value by dividing the $/MW-year value by 1-12

(EFORd+Derate). 13

Q. The Company has proposed an estimated ELCC of 39% for solar in its filing. Do 14

you agree with this? 15

A. I believe that the Company should use MISO’s ELCC estimate of 50%1 for the 16

first year for generators that have no operational data. The ELCC can then be 17

updated according to MISO as operational data is received. 18

Q. Does this complete your reopened responsive testimony? 19

A. Yes it does. 20

1

https://www.misoenergy.org/Library/Repository/Meeting%20Material/Stakeholder/LOLEWG/2016/20161130/20161130%20LOLEWG%20Item%2002b%20Solar%20Capacity%20Credit%20Review.pdf

450



451

1 JUDGE SNIDER: Ms. Newell.

2 MS. NEWELL: Thank you, your Honor.

3 Pursuant to the stipulation of the parties to waive

4 cross-examination of Mr. Brian Steglitz, the City of Ann

5 Arbor moves to bind in the reopened direct testimony of

6 Brian Steglitz, which consists of a cover page and six

7 pages of questions and answers. In addition, the City of

8 Ann Arbor moves for the admission of Exhibit CAA-24,

9 which was filed with Mr. Steglitz's reopened direct

10 testimony.

11 JUDGE SNIDER: All right. Pursuant to

12 stipulation of the parties, the reopened direct testimony

13 of Witness Steglitz is bound into the record; and Exhibit

14 CAA-24 is admitted.


16 - - -

17

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20

21

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23

24

25


STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION *****

In the matter, on the Commission's Own Motion, ) Case No. U-18091 establishing the method and avoided cost calculation ) for DTE ELECTRIC COMPANY to fully comply ) with the Public Utilities Regulatory Policy Act ) of 1978, 16 USC 2601 et seq. ) ________________________________________ )

REOPENED DIRECT TESTIMONY

OF

BRIAN STEGLITZ

ON BEHALF OF

THE CITY OF ANN ARBOR, MICHIGAN

452

2

Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 1

A. Brian Steglitz, 919 Sunset Rd., Ann Arbor, MI. 2

3

Q. ARE YOU THE SAME BRIAN STEGLITZ THAT PROVIDED DIRECT AND 4

REBUTTAL TESTIMONY PREVIOUSLY IN THIS PROCEEDING? 5

A. Yes, I am. 6

7

Q. ARE YOU SPONSORING ANY EXHIBITS? 8

A. Yes, I am sponsoring the following exhibit: CAA-24 (BS-2). [standard offer tariff] 9

10

Q. IN ITS JULY 31, 2017 ORDER IN THIS CASE, THE COMMISSION NOTED 11

THAT THE PARTIES MAY FILE, “PROPOSED INPUTS TO BE USED FOR 12

DEVELOPING AVOIDED CAPACITY COST USING A NATURAL GAS 13

COMBUSTION TURBINE UNIT AND AVOIDED ENERGY COST USING A 14

NATURAL GAS COMBINED CYCLE UNIT AS PROXY PLANTS AND A 15

CALCULATION OF INVESTMENT COST ATTRIBUTABLE TO ENERGY.” 16

ARE YOU PROVIDING THESE PROPOSED INPUTS AND CALCULATIONS? 17

A. Only in part. The City’s two hydro plants, which are Qualifying Facilities ("QFs") and so 18

will be subject to the Commission’s avoided cost determinations, are not up for contract 19

renewal until 2036. The Commission has indicated in its July 31 Order that it will 20

reconsider the avoided cost rate biannually. The City is therefore less focused on the 21

actual numbers that come out of this round of rate setting, and more focused on issues 22

453

3

that may set longer-term precedent for how such rates are set in future rounds – 1

particularly with respect to hydro plants. 2

3

For these reasons, my testimony here focuses more on seeking clarification of the 4

Commission’s rulings on renewal of expiring contracts, adjustment of QF capacity based 5

on the Effective Load Carrying Capacity ("ELCC"), and the structure and language of the 6

proposed Standard Offer tariff. 7

8

Q. WHAT CLARIFICATION ARE YOU SEEKING ON THE COMMISSION’S 9

RULING ON RENEWAL OF EXPIRING CONTRACTS? 10

A. On page 15 of its July 31 Order, the Commission stated that: 11

The Commission also finds that existing QFs with expiring contracts 12 should have their contracts renewed at the full avoided cost rate, whether 13 or not the company forecasts a capacity shortfall over the planning 14 horizon. As the Staff observed, the capacity and energy supplied by these 15 QFs is already taken into account in the company’s determinations about 16 future capacity additions. 17 18

This language in the July 31 Order suggests to the City that when its contracts come up 19

for renewal, it can depend upon a continued ability to sell both its capacity and its energy 20

to DTE at DTE’s full avoided cost. However, the next paragraph in the July 31 Order 21

seems to take a different position. It states: “The Commission concurs with the Staff’s 22

recommendation that if no capacity is needed during the entire 10-year planning horizon, 23

then DTE Electric shall make a filing so indicating, and the avoided cost for capacity 24

shall be reset to the MISO PRA.” This paragraph suggests to the City that the 25

Commission would allow DTE to favor its own resources (which are not paid based on 26

MISO’s PRA) over existing contracted-for QF resources such as the City’s two hydro 27

454

4

facilities by allowing DTE to pay these QFs only the MISO PRA for capacity payments 1

on renewal. 2

3

The Commission’s positions in these two paragraphs appear to the City to be in conflict 4

with one another. Therefore we seek clarification from the Commission on its intent. 5

The City also provides input to assist the Commission in its clarification of its position. 6

In the City’s view, if the Commission intended the statements in the second paragraph to 7

apply to existing QFs on the DTE system, such as the City’s two hydroelectric facilities, 8

then PURPA’s goals would be subverted, as the utility would be allowed over time to 9

replace QF suppliers with its own utility-owned resources through the disproportionate 10

financial pressure created by paying QFs through the unsustainably low pricing of the 11

PRA market, while utility-owned resources receive full cost recovery under Michigan’s 12

regulated structure.1 13

14

Q. WHAT CLARIFICATION ARE YOU SEEKING ON THE COMMISSION’S 15

RULING ON THE USE OF THE ELCC? 16

A. In its July 31 Order, the Commission stated that it, “agrees with the Staff’s and to some 17

extent DTE Electric’s recommendation, that it is reasonable to adjust QF capacity in 18

accordance with ELCC to reflect availability during seasonal and daily peak times.” July 19

31 Order, p. 14. Staff’s recommendation was that the ELCC (i.e., the Midcontinent 20

Independent System Operator's ("MISO") Zonal Resource Credits) be applied only to 21

non-baseload generation: “Staff recognizes that ZRCs would only be applicable to 22

1 On MISO’s unsustainable pricing for capacity in its PRA, see 2 Tr 192-194, and for DTE’s own costs for

its owned capacity and energy, see 2 Tr 273 and Exhibit CAA-1.

455

5

nonbaseload energy.” Staff Initial Brief, p. 5. Hydroelectric plants, which run 24 hours a 1

day, seven days a week, are considered baseload power. While a run-of-the-river hydro 2

is not able to adjust its output to follow peaks in demand, it is nevertheless always 3

operating and is not an intermittent nor a peaking facility, regardless of how MISO 4

accounts for such facilities for reliability credits - ZRCs. The Commission also notes in 5

its July 31 Order that it agrees with DTE’s proposal for use of ELCC only “to some 6

extent.” July 31 Order, p. 14. In its discussion of DTE’s proposal for use of ELCC, the 7

Commission also notes the City’s concerns that the application of ELCCs to its units, as 8

DTE proposes, “undervalues ‘the reliability, sustainability, environmental and economic 9

development attributes of these QFs to the State and to local areas in which they operate.” 10

July 31 Order, p. 10, citing the City’s Initial Brief, p. 51. As the City noted in the same 11

paragraph of its Initial Brief cited by the Commission, its plants provide baseload power 12

and black start capability, benefits that would be undervalued if treated like an 13

intermittent resource. City’s Initial Brief, p. 52. The City is also concerned that applying 14

a reliability standard – MISO's ZRCs – to the contracted capacity amount and payment 15

calculation will effectively reduce the output and saleable amount of capacity the City’s 16

plants can generate and provide to DTE. The City therefore seeks clarification that the 17

Commission’s statement that it “agrees with Staff’s and to some extent DTE Electric’s 18

recommendation” with respect to applying ELCCs, means that it intended to apply 19

ELCCs/ZRCs only to the nonbaseload, intermittent resources specified by Staff, and not 20

to baseload facilities, such as the City’s run-of-the-river hydro units. 21

22

23

456

6

Q. DOES THE CITY HAVE ANY PROPOSALS AT THIS TIME FOR THE INPUTS 1

SOUGHT BY THE COMMISSION? 2

A. As discussed above, the City does not intend to propose specific numbers for inputs. 3

However, the City does believe that the numbers chosen by the Commission should be 4

transparent and accessible to QFs, and so use of confidential utility numbers is 5

problematic. Because the utility is an interested party in these proceedings, whose 6

interests are divergent from and opposed to the interests of the QFs, it would be 7

inappropriate for the Commission to rely on numbers that are protected from public 8

scrutiny and not able to be readily rebutted by QFs. For this reason, the City believes that 9

numbers from such public sources as the government’s Energy Information Agency 10

(“EIA”) are more appropriate than what might be self-serving calculations by the utility, 11

and that even publicly available numbers should be subject to scrutiny and examination 12

in a contested process during the biannual reviews. 13

14

That said, it is also true that in this instance, DTE has just filed a Certificate of Necessity 15

in Case No. U-18419 before the Commission. Because in that filing the utility does not 16

have any incentive to understate its costs, the City believes that it would be appropriate 17

for the Commission to use the numbers proposed by DTE for its new plant as the basis 18

for avoided cost payments to QF facilities. The City has an outstanding discovery 19

request to DTE seeking the input-equivalent information from the Company about its 20

proposed Belle River power plant. As of the date of this filing, DTE has not provided a 21

response nor an explanation for its delay in responding. 22

23

457

7

Q. DOES THE CITY HAVE ANY RECOMMENDATIONS WITH RESPECT TO 1

THE STANDARD OFFER TARIFF? 2

A. Yes. Aside from the avoided cost calculations generally, the City’s positions on which 3

are provided above, the City has comments on particular provisions of the Standard Offer 4

tariff as presented by Staff. As the Commission has asked parties to file “a proposed 5

Standard Offer tariff,” the City provides a redlined version of the Staff’s proposed tariff 6

for the Commission’s consideration as Exhibit CAA-24 (BS-2). Of particular concern to 7

the City is the Staff language included in the Capacity and Energy sales portion of the 8

Standard Offer tariff. This language attempts to limit the available capacity and energy 9

that the City's QFs can provide in several different regards, including by stating that the 10

capacity will be on an "as needed" basis, and by stating that capacity and energy will 11

subject to the amounts that "MISO determines the seller Qualifying Facility can supply." 12

The City believes that both provisions would be inconsistent with PURPA if accepted by 13

the Commission. 14

15

Q. DOES THIS CONCLUDE YOUR TESTIMONY? 16

A. Yes. 17

18

12121082_2.docx 19

458

459

1 JUDGE SNIDER: Anything else on behalf of

2 City of Ann Arbor?

3 MS. NEWELL: Well, actually, on behalf of

4 Margrethe Kearney, who could not be here this morning,

5 there was a prior stipulation of the parties.

6 Ms. Kearney represents the Environmental Law & Policy

7 Center, Solar Energy Industries Association, and Vote

8 Solar, as well as The Ecology Center, and she has asked

9 that I read into the record her motion to bind in the

10 supplemental testimony of Douglas B. Jester, consisting

11 of a cover page and seven pages of questions and answers;

12 and for the admission of Exhibit ELP-9, which is one

13 page, and ELP-10, which is also one page.

14 JUDGE SNIDER: O.K. Based on the

15 stipulation of the parties, the reopened testimony of

16 Witness Jester is bound into the record; and Exhibits

17 ELP-9 and ELP-10 are admitted.


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STATE OF MICHIGAN MICHIGAN PUBLIC SERVICE COMMISSION

In the matter, on the Commission’s own motion, establishing the method and avoided cost calculation for DTE ELECTRIC COMPANY to fully comply with the Public Utilities Regulatory Policy Act of 1978, 16 USC 2601 et seq.

) ) ) ) ) )

Case No. U-18091

SUPPLEMENTAL TESTIMONY OF

DOUGLAS B. JESTER

ON BEHALF OF

ENVIRONMENTAL LAW AND POLICY CENTER, THE ECOLOGY CENTER, THE SOLAR ENERGY INDUSTRIES ASSOCIATION, AND VOTE SOLAR

August 15, 2017

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U-18091 Jester– 1 8/15/2017

Q. State your name, business name and address. 1

A. My name is Douglas B. Jester. I am a partner of 5 Lakes Energy LLC, a Michigan 2

limited liability corporation, located at 120 N Washington Square, Suite 805, Lansing, 3

Michigan 48933. 4

5

Q. On whose behalf are you appearing in this case? 6

A. I am appearing here as an expert witness on behalf of The Ecology Center, the 7

Environmental Law and Policy Center, the Solar Energy Industries Association, and 8

Vote Solar (the “Joint Intervenors”). 9

10

Q. Did you file direct testimony in this case on behalf of the Joint Intervenors? 11

A. Yes. 12

13

Q. Are you proposing any additional exhibits with this supplemental testimony? 14

A. Yes. 15

• Exhibit ELP-9 Natural Gas Price Forecasts 16

• Exhibit ELP-10 Proposed Final Energy Rate 17

18


A. In its July 31, 2017 Order, the Commission reopened the record in this case so that “the 20

parties to this proceeding may proposed inputs to be used for developing avoided 21

capacity cost using a natural gas combustion turbine unit and avoided energy cost using a 22

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U-18091 Jester– 2 8/15/2017

natural gas combined cycle unit as proxy plants and a calculation of investment cost 1

attributable to energy” 2

3

My testimony is responsive to that order. 4

5

Q. What values do you recommend the Commission adopt for the avoided capacity 6

cost of a natural gas combustion turbine? 7

A. I recommend that the Commission adopt the values recommended by Staff in its August 8

11, 2017 Testimony in U-18090, as illustrated in Staff’s Exhibit S-14. These values are 9

based on methods and estimates from recognized public sources and have been refined 10

from Staff’s earlier testimony in the present case. 11

12

Q. What values do you recommend the Commission adopt for the avoided capacity 13

cost of a combined cycle natural gas turbine? 14


11, 2017 Testimony in U-18090, as illustrated in Staff’s Exhibit S-14. These values are 16

based on methods and estimates from recognized public sources and have been refined 17

from Staff’s earlier testimony in the present case. 18

19

Q. What values do you recommend the Commission adopt for the incremental cost of 20

energy of a combined cycle natural gas turbine? 21


462

U-18091 Jester– 3 8/15/2017

11, 2017 Testimony in U-18090, as illustrated in Staff’s Exhibit S-14. This value is 1

calculated from the capacity costs of a combustion turbine and a combined cycle natural 2

gas turbine and has the value $7.68 per MW-year. 3

4

Q. What natural gas price forecast do you recommend the Commission adopt to 5

establish avoided costs for DTE Electric Company? 6

A. I recommend the Commission rely on publicly available sources that do not have any 7

incentives concerning their forecasts, and to particularly consider the forecasts produced 8

by the Energy Information Administration (EIA) of the US Department of Energy. The 9

most recent long-term forecasts issued by EIA are contained within its 2017 Annual 10

Energy Outlook (AEO).1 11

12

EIA’s forecasted natural gas delivered prices for the North Central region best captures 13

the natural gas costs an electric power plant in Michigan would incur for the purposes of 14

fueling electricity generation resources. EIA also forecasts general natural gas prices, of 15

which the most commonly cited is the Henry Hub price, which is a widely used index of 16

natural gas commodity prices. However, not all natural gas fueling electric generating 17

resources in Michigan comes from the Henry Hub. 18

19

Delivered prices are closer to the actual price paid for natural gas used to fuel electric 20

power plants in Michigan. Because the Commission, through its Staff, has previously 21

1 The most recent versions of EIA’s AEOs are available at https://www.eia.gov/outlooks/aeo/

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https://www.eia.gov/outlooks/aeo/

U-18091 Jester– 4 8/15/2017

considered the Henry Hub spot market price forecast, I am also presenting the EIA 1

Henry Hub spot price to show the difference between EIA’s delivered price at electric 2

power plants in the East North Central region and the Henry Hub spot price as the 3

transportation cost. See Exhibit ELP-9. 4

5

The delivered natural gas price forecasts for electricity generation in Michigan best 6

captures avoided costs because it takes into account transportation costs. The 7

Commission should be cautious about adopting a transportation charge separately from a 8

reference commodity price without great care to ensure that these elements of the 9

delivered price are logically consistent. The only alternative to using delivered price 10

forecasts would be to use a price forecast such as Henry Hub and then a transportation 11

forecast and other forecasts to capture separate charges related to its end-use purpose in 12

electricity generation. This alternative is much more complicated and has a much larger 13

room for error. Delivered prices take into account all of this information and provide the 14

best representation of avoided natural gas costs. 15

16

As the Commission expressed in U-18090 a preference for a schedule of future avoided 17

energy costs, which the Commission has not indicated that it would index to inflation or 18

another general price index, it is most appropriate to use EIA’s nominal price forecast 19

rather than its 2016 “real” price forecast. Exhibit ELP-9 shows the EIA 2017 Annual 20

Energy Outlook forecasts the nominal natural gas prices as delivered to electric power 21

plants in the East North Central region, nominal natural gas prices in the Henry Hub spot 22

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U-18091 Jester– 5 8/15/2017

market, and the difference between these identified as the “Transportation Cost”. The 1

Transportation Cost column is an illustration of how transportation and other costs affect 2

the end-use price for natural gas electricity generation in Michigan. 3

4

Q. Please explain the source and calculations you used to produce Exhibit ELP-9. 5

A. EIA provides a “data browser” for the 2017 Annual Energy Outlook, which can be 6

accessed via the world-wide web. Various data tables can be obtained through 7

eia.gov/outlooks/aeo/tables_ref.php. “Table 13. Natural Gas Supply, Disposition, and 8

Prices” contains EIA’s national forecasts, including nominal Henry Hub spot prices, 9

while “Table 3.3 East North Central” contains the nominal delivered prices of natural gas 10

(and other forms of energy) for various disposition sectors in the region that includes 11

Michigan. 12

13

Q. What energy payment schedule is consistent with the natural gas price forecast in 14

Exhibit ELP-9? 15

A. That calculation depends on the heat rate and ICE parameters previously adopted by the 16

Commission as well as the variable operations and maintenance cost. The heat rate 17

adopted by the Commission in U-18090 is 6.600 MMBTu/MWh. I used the 2021 ICE 18

parameter of $7.68 per MWh, as I testified above. I made annual inflation adjustments to 19

this value using the Global Insights index of capital costs previously relied upon by Staff. 20

465

https://www.eia.gov/outlooks/aeo/tables_ref.php

U-18091 Jester– 6 8/15/2017

To determine the cost of variable operations and maintenance of a combined cycle 1

natural gas plant, I used EIA’s “Capital Cost Estimate for Utility Scale Electric 2

Generating Plant,” prepared in conjunction with EIA’s preparation of the 2017 Annual 3

Energy Outlook, for conventional combined cycle natural gas plant of $3.50/MWh in 4

2016. I made annual inflation adjustments to this value using the Global Insights index of 5

employment costs previously relied upon by Staff. 6

7

I further adjusted the resulting avoided cost of energy at the proxy plant by a line loss 8

factor of 1.0237, which only reflects line losses in transmission.2 9

10

The calculations above and the resulting avoided energy cost schedule requested by the 11

Commission are shown in Exhibit ELP-10. This exhibit does not show capacity value. 12

13

Q. The Commission’s July 31st Order concluded that it is “reasonable to adjust QF 14

capacity in accordance with ELCC to reflect availability during seasonal and daily 15

peak times” and referred to “MISO’s ELCC.” Do you have any suggestions to 16

ensure that Qualifying Facilities (QFs) are compensated for their capacity 17

consistent with the Commission’s decision on this matter? 18

A. Yes. The Commission should approve language in the tariff that explains how avoided 19

capacity costs and MISO ELCC interacts. MISO uses something called “Zonal Resource 20

Credits” (ZRCs) as a measure of availability. It is important to be clear how ZRCs will 21

2 This value was adopted in U-18090. As this is an average transmission line loss, it should be almost identical for DTE.

466

U-18091 Jester– 7 8/15/2017

be applied in the tariff. Below is suggested language: 1

Capacity value for intermittent resources is based on MISO zonal 2

resource credits (ZRCs). Capacity value paid to QFs does not depend on 3 whether the Company actually obtains ZRCs for such capacity, only that 4 the Company could obtain ZRCs for the QF capacity. Capacity value paid 5 to a QF is in units of $/ZRC. MISO ZRCs are equal to the projects 6 nameplate capacity (in MW AC) modified by the MISO effective load 7 carrying capacity (ELCC) calculation. MISO ELCC for the term of the 8 QF contract is calculated pursuant to the MISO Business Practices 9 Manual (BPM) effective at the time of the QF contract execution. The 10 currently effective ELCC calculation is provided in MISO BPM-011-r16 11 § 4.2.3, which recognizes capacity based on accumulated, historical 12 performance. 13

This language provides clarity to future QF developers. With this basic explanation, 14

future QF developers will be able to calculate how much capacity value their proposed 15

projects should expect to receive. The ability to calculate avoided capacity cost payments 16

is necessary to obtain project financing. 17

18

In addition, this language ensures that QFs are compensated for the capacity their 19

projects could provide, consistent with the Commission’s decision to use MISO’s ELCC, 20

(namely, ZRCs) as the basis for capacity determination. This language preempts the 21

unlikely situation that a utility contracts with a QF but chooses to not obtain ZRCs from 22

MISO, and then the utility claims it is not required to pay for the QF capacity because 23

the utility chose to not seek ZRCs from MISO. 24

25

Q. Does that complete your testimony? 26

A. Yes. 27

467

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1 JUDGE SNIDER: Anything else, Ms. Newell?


3 JUDGE SNIDER: All right. The last thing

4 we have to do according the Commission's July 31 order is

5 set dates for briefing. Off the record the parties

6 indicated that they would file initial briefs on

7 September 22, 2017, with reply briefs due October 5,

8 2017.

9 Is that everyone's agreement on the

10 briefing date? Mr. Christinidis?

11 MR. CHRISTINIDIS: Yes, your Honor.

12 JUDGE SNIDER: Ms. Durian?

13 MS. DURIAN: Yes, your Honor.

14 JUDGE SNIDER: Ms. Newell?

15 MS. NEWELL: Yes, your Honor.

16 JUDGE SNIDER: All right. So those will

17 be the dates. I will issue a scheduling memo that

18 indicates that those are the dates for briefing.

19 Mr. Christinidis, do you have anything

20 else this morning?

21 MR. CHRISTINIDIS: Nothing further, your

22 Honor.

23 JUDGE SNIDER: Ms. Durian?


25 JUDGE SNIDER: Ms. Newell?


469


2 JUDGE SNIDER: All right. That's all we

3 need to do. Thank you, all. And we'll adjourn this

4 morning.

5 MR. CHRISTINIDIS: Thank you, your Honor.

6 MS. DURIAN: Thank you.

7 MS. NEWELL: Thank you.

8 (At 10:28 a.m., the hearing concluded.)

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470

1

2 C E R T I F I C A T E

3

4 I, Lori Anne Penn (CSR-1315), do hereby

5 certify that I reported in stenotype the proceedings had

6 in the above-entitled matter, that being Case No.

7 U-18091, before Martin D. Snider, J.D., Administrative

8 Law Judge with Michigan Administrative Hearing System, at

9 the Michigan Public Service Commission, 7109 West Saginaw

10 Highway, Lansing, Michigan, on Wednesday, September 13,

11 2017; and do further certify that the foregoing

12 transcript constitutes a true and correct transcript of

13 my stenotype notes.

14

15

16

17 ______________________________________

18 Lori Anne Penn, CSR-1315

19 33231 Grand River Avenue

20 Farmington, Michigan 48336

21

22

23 Dated: September 17, 2017

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