re: case no. u-18239 – in the matter, on the commission’s

fl0817-1-230

A CMS Energy Company

August 7, 2017

Ms. Kavita Kale Executive Secretary Michigan Public Service Commission 7109 West Saginaw Highway Post Office Box 30221 Lansing, MI 48909

Re: Case No. U-18239 – In the matter, on the Commission’s own motion, to open a docket to implement the provisions of Section 6w of 2016 PA 341 for CONSUMERS ENERGY COMPANY’S service territory.

Dear Ms. Kale:

Enclosed for electronic filing in the above-captioned case, please find the Rebuttal Testimony and Exhibits of Consumers Energy Company Witnesses Josnelly C. Aponte, Laura M. Collins, and David F. Ronk, Jr.

This is a paperless filing and is therefore being filed only in a PDF format. I have also included a Proof of Service showing electronic service upon the parties.

Sincerely,

Kelly M. Hall

cc: Hon. Mark D. Eyster, Administrative Law Judge Parties per Attachment 1 to Proof of Service

General Offices: LEGAL DEPARTMENT One Energy Plaza Tel: (517) 788-0550 CATHERINE M REYNOLDS

Senior Vice President and General Counsel

Ashley L Bancroft Robert W Beach Don A D’Amato Robert A. Farr Gary A Gensch, Jr. Kelly M Hall Gary L Kelterborn Chantez P Knowles Mary Jo Lawrie Jason M Milstone Rhonda M Morris Deborah A Moss* Mirče Michael Nestor James D W Roush Scott J Sinkwitts Adam C Smith Janae M Thayer Bret A Totoraitis Anne M Uitvlugt Aaron L Vorce

Attorney

Jackson, MI 49201 Fax: (517) 768-3644

*Washington Office: 1730 Rhode Island Ave. N.W. Suite 1007

Tel: (202) 778-3340 MELISSA M GLEESPEN Vice President, Corporate Secretary and Chief Compliance Officer

SHAUN M JOHNSON Vice President and Deputy General Counsel

H Richard Chambers Eric V Luoma Kimberly C Wilson Assistant General Counsel

Washington, DC 20036 Fax: (202) 778-3355

Writer’s Direct Dial Number: (517) 788-2910 Writer’s E-mail Address: [email protected]

S T A T E O F M I C H I G A N

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter, on the Commission’s own motion, ) to open a docket to implement the provisions of ) Section 6w of 2016 PA 341 for ) CONSUMERS ENERGY COMPANY’S ) Case No. U-18239 service territory. )

)

REBUTTAL TESTIMONY

OF

JOSNELLY C. APONTE

ON BEHALF OF

CONSUMERS ENERGY COMPANY

August 2017

JOSNELLY C. APONTE REBUTTAL TESTIMONY

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Q. Please state your name and business address. 1

A. My name is Josnelly C. Aponte, and my business address is One Energy Plaza, Jackson, 2

Michigan 49201. 3

Q. Are you the same Josnelly C. Aponte who previously filed direct testimony in this case? 4

A. Yes, I am. 5

Q. What is the purpose of your rebuttal testimony in this proceeding? 6

A. The purpose of my rebuttal testimony in this proceeding is to address certain arguments 7

and proposals related to the Cost-of-Service Study (“COSS”) made by witnesses 8

Nicholas M. Revere, on behalf of the Michigan Public Service Commission (“MPSC” or 9

the “Commission”) Staff (“Staff”); Jeff D. Makholm, on behalf of Constellation 10

NewEnergy, Inc. (“CNE”); James R. Dauphinais, on behalf of the Association of 11

Businesses Advocating Tariff Equity (“ABATE”); and Alex J. Zakem on behalf of 12

Energy Michigan, Inc (“Energy Michigan”). 13

Q. Please identify the exhibits you are sponsoring. 14

A. I am sponsoring the following exhibits: 15

Exhibit A-16 (JCA-4) Case No. U-17032, Exhibit S-2 (BJ-2); 16

Exhibit A-17 (JCA-5) Staff’s Discovery Response No. 18239-CE-ST-5; 17

Exhibit A-18 (JCA-6) Case No. U-17032, Exhibit EM-6; 18

Exhibit A-19 (JCA-7) ABATE’s Discovery Response No. 18239-CE-AB-9; 19 and 20

Exhibit A-20 (JCA-8) Case No. U-18239, MPSC Staff Audit Request 21 No. 007 – Stranded Cost Collection Summary. 22

Q. Were these exhibits prepared by you or under your supervision? 23

A. Yes, they were. 24


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Rebuttal To Staff Witness Revere 1

Q. Do you agree with Mr. Revere’s conclusion at page 6, lines 8 through 13, that Consumers 2

Energy Company (“Consumers Energy” or the “Company”) has not properly identified 3

capacity-related costs in its filing and accepts Staff’s proposal per Exhibit S-1.1? 4

A. No. Section 6w(3)(a) of Public Act 341 (“Act 341”) requires to “include the capacity-5

related generation costs included in the utility’s base rates” for the calculation of the State 6

Reliability Mechanism (“SRM”) capacity charge. In order to comply with this 7

requirement, the Company followed the National Association of Regulatory Utility 8

Commissioners (“NARUC”) principles in the Electric Utility Cost Allocation Manual, 9

pages 19 through 21 and 35, which establish the following in regards to the 10

functionalization and classification of production costs (emphasis added): 11

“The production function consists of the costs associated with 12 power generation and wholesale purchases.” 13

* * * * 14

“[The administrative and general function] costs may be 15 functionalized by relating them to specific groups of costs or other 16 characteristics of the major cost functions…” 17

* * * * 18

“Costs that are based on the generating capacity of the plant, such 19 as depreciation, debt service and return on investment, are 20 demand-related costs.” 21

* * * * 22

“Fixed production costs are those revenue requirements associated 23 with generating plant owned by the utility, including cost of 24 capital, depreciation, taxes and fixed [Operating and Maintenance]. 25 (…) Fixed production costs vary with capacity additions, not with 26 energy produced from given plant capacity, and are classified as 27 demand-related.” 28


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Staff’s proposal takes an approach of selecting the costs that are currently allocated based 1

on the 75/25 weighting methodology (75% demand and 25% total energy) and 2

determined that the Company’s capacity-related costs are limited to the 75% portion of 3

the selected costs. With this approach, Staff does not recognize other capacity-related 4

costs, such as the intangible plant assigned to the production function, which is clearly 5

classified as a demand-related cost on page 35 of the NARUC manual, in addition to 6

other joint and common costs subject to production functionalization based on labor 7

ratios or plant-in-service, which are also considered fixed production costs, because they 8

do not change with the amount of energy produced, hence classified as demand-related as 9

well. 10

Q. At pages 6 and 7 of his direct testimony, Mr. Revere stated that “Staff split the costs 11

currently allocated by the production allocator into capacity- and non-capacity-related 12

portions, using the 75-25 split.” Mr. Revere further stated (Direct Testimony, page 7) 13

“[t]he 75% portion identified as capacity-related is then allocated on the 4 [Coincident 14

Peak] portion of the former combined allocator to identify the capacity-related revenue 15

requirement by COSS class.” Is it appropriate to exclude the 25% of production costs 16

which are allocated based on customers’ annual energy usage, as suggested by 17

Mr. Revere? 18

A. No, it is not. As indicated previously, Staff is not considering two important steps in the 19

development of the COSS: functionalization and classification. The use of a partial 20

energy weighting method to allocate a portion of the production plant costs to the 21

different customer classes should not be construed as if this portion of the costs is 22

classified as energy-related (NARUC, page 49). In other words, the 75/25 cost allocation 23


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methodology is a means to allocate the costs of production among the customer classes; it 1

is not intended nor suited to defining what constitutes a capacity production cost. 2

Q. Has Staff previously opined on the definition of a capacity cost for purposes of 3

calculating a capacity charge to be applied to Retail Open Access (“ROA”) and bundled 4

retail electric service customers? 5

A. Yes. In Case No. U-17032, which was a proceeding in which a State Compensation 6

Mechanism (“SCM”) capacity charge was considered and approved for Indiana and 7

Michigan Power Company (“I&M”), witnesses for Staff supported, with minor 8

adjustments, I&M’s method of calculating a capacity charge which would apply to ROA 9

and bundled service customers which was developed in a manner consistent with the 10

methodology used by the Company in this case. Staff’s proposal in this case to define 11

capacity costs as 75% of total production costs, which are allocated based on demand, is 12

contrary to the approach Staff used in Case No. U-17032. 13

Q. Please explain. 14

A. In Case No. U-17032, Staff witness Bonnie Janssen testified “to support an update of 15

[I&M’s] cost of service and rate design. This cost of service update is the result of 16

Staff’s review of I&M proposed state compensation mechanism for alternative electric 17

supplier (AES) capacity in its Michigan service territory.” Ms. Janssen explained the 18

methodology for I&M’s SCM capacity as follows: 19

“The Company filed a cost of service and corresponding rate 20 design spreadsheets supporting a capacity pricing proposal. I&M’s 21 proposal utilized Michigan-specific ratemaking principles as 22 ordered by this Commission in its May 24, 2012 Order Initiating 23 Proceeding and Notice of Hearing. In developing its state 24 compensation mechanism, I&M filed a cost of service study, 25 submitted as Exhibit A-2, which was based upon 2012 test year 26 assumptions and forecasts. This cost of service study was the 27


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result of a settlement agreement that was approved by the 1 Commission on February 14, 2012 in Case No. U-16801. The 2 company adjusted the cost of service study to remove the enhanced 3 security costs, which was an amount of $118,440. 4

5“Next, I&M witness Nancy A. Heimberger made adjustments in 6 the production demand component, dividing this component into 7 capacity and non-capacity components. These adjustments were 8 identified on pages 3-5 of Ms. Hemberger’s pre-filed direct 9 testimony. Included in these adjustments were the removal of 10 transmission-related costs, demand-related ancillary service costs, 11 and a credit for energy-related off system sales (OSS) margins for 12 the capacity charges. I&M maintains that its methodology ensures 13 that all of its customers, either full service or open access 14 distribution (OAD), will pay the same cost-based amount for 15 capacity under this state compensation mechanism, since the 16 customers will be depending upon the same capacity.” Case No. 17 U-17032, 3 TR 405-406. 18

19 Q. Is Consumers Energy’s method of using the U-17990-approved COSS and separating 20

production costs into capacity- and non-capacity-related costs for purposes of 21

determining the SRM capacity charge consistent with the approach used by I&M in Case 22

No. U-17032? 23

A. Yes. Consumers Energy’s method of determining capacity- and non-capacity-related 24

costs, as described in my direct testimony, is the same methodology as that used by I&M 25

in Case No. U-17032, and it is consistent with accepted Michigan ratemaking principles. 26

Q. Did Staff support I&M’s method of determining the capacity-related production costs to 27

be included in the SCM capacity charge in Case No. U-17032? 28

A. Yes. 29


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Q. Please explain. 1

A. With the exception of a minor adjustment of $244,348,1 Staff witness Janssen supported 2

I&M’s method of calculating capacity- and non-capacity production costs and using the 3

resulting capacity production costs to be recovered from pursuant to the SCM capacity 4

charge applied to ROA (or Open Access Distribution (“OAD”)) customers and full 5

service electric customers. Ms. Janssen testified as follows: 6

“Q. Does Staff agree with the state compensation mechanism 7 proposal as filed by I&M, with Staff’s adjustments, in this 8 case? 9

“A. Yes. Staff believes that I&M’s proposed approach to 10 establish a state capacity mechanism for AES[s] in its 11 Michigan service territory is reason able given the 12 following: 13

“1. I&M was required to file a state compensation 14 mechanism based upon Michigan-specific ratemaking 15 principles. Based on Staff’s review of the proposed 16 mechanism, it believes that I&M’s proposal follows 17 Michigan ratemaking principles. 18

“2. I&M is a vertically integrated utility with generation, 19 transmission, and distribution, and is allowed to 20 participate in the capacity market as a fixed resource 21 requirement (FRR) entity under the Pennsylvania-22 New Jersey-Maryland (PJM) Reliability Assurance 23 Agreement (RAA). 24

“3. In I&M’s last Michigan rate case, Case No. U-16801, 25 the Company had no OAD customers in its service 26 territory, and as of February 15, 2012, no AES had 27 committed capacity to the Company’s capacity 28 market. 29

1 Staff’s adjustment of $244,348 reduced I&M’s capacity power supply charges and increased the non-capacity power supply charges. I&M did not oppose the adjustment, and agreed that it properly assigned amounts which were entirely transmission-related. See, MPSC Case No. U-17032, September 25, 2012 Order, page 7.


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“4. The MPSC has not ordered I&M to separate its 1 generation and power marketing business from its 2 transmission and distribution businesses.” Case No. 3 U-17032, 3 TR 407. 4

Q. Did Staff address the definition of capacity power supply charges and non-capacity 5

power supply charges for purposes of developing its position on I&M’s SCM capacity 6

charge in Case No. U-17032? 7

A. Yes. Staff witness Janssen’s Exhibit S-2 (BJ-2) in Case No. U-17032 was her audit 8

question in which she requested that I&M define the terms “Capacity Power Supply” and 9

“Non-Capacity Power Supply.” A copy of Ms. Janssen’s Exhibit S-2 (BJ-2) from Case 10

No. U-17032 is my Exhibit A-16 (JCA-4). Ms. Janssen’s direct testimony in Case No. 11

U-17032 accepted I&M’s definitions, and accepted the inclusion of the costs included in 12

“Capacity Power Supply” as those which should be recovered from ROA customers and 13

full service customers pursuant to I&M’s SCM capacity charge. 14

Q. What are the definitions of “Capacity Power Supply” and “Non-Capacity Power Supply” 15

used by I&M and accepted by Staff in Case No. U-17032? 16

A. As shown on Exhibit A-16 (JCA-4), the definitions are as follows: 17

“Capacity Power Supply charges are the retail power supply 18 charges for costs incurred by I&M in order to meet its customers' 19 capacity needs.” 20

“Non-Capacity Power Supply charges are the retail power supply 21 charges for generation and transmission costs that are not included 22 as Capacity Power Supply charges.” 23


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Q. Are the definitions of “Capacity Power Supply” and “Non-Capacity Power Supply” used 1

by I&M, and accepted by Staff, in Case No. U-17032 consistent with Consumers 2

Energy’s definition of capacity- and non-capacity-related power supply costs in this 3

proceeding? 4

A. Yes, they are. Moreover, Staff witness Janssen recommended “these definitions be 5

included on I&M’s tariff sheets.” (MPSC Case No. U-17032; 3 TR 408.) 6

Q. Did Staff provide a definition of Capacity Power Supply in this case? 7

A. Staff witness Revere stated (pages 6 and 7 of his direct testimony) that he designated 8

capacity-related costs as the production costs which are allocated on a 75% demand basis, 9

and excluded from capacity-related costs the production costs which are allocated on a 10

25% energy basis. Consumers Energy asked Staff to provide a definition of “Capacity 11

Power Supply” and “Non-Capacity Power Supply” in discovery in this case, but Staff 12

declined to provide the requested definitions, citing the fact that Staff did not use those 13

terms in Mr. Revere’s direct testimony in this case. See Exhibit A-17 (JCA-5). 14

Q. Are there other reasons why Staff’s position on the methodology for determining the 15

SRM capacity charge in this case is inconsistent with Staff’s position on the methodology 16

for determining the SCM capacity charge in Case No. U-17032? 17

A. Yes. Staff witness Revere’s proposal to reduce the total production cost included in 18

Consumers Energy’s COSS by the 25% of those costs which are allocated on an energy 19

basis is inconsistent with the embedded cost-of-service-based methodology which was 20

used by I&M and supported by Staff witnesses in Case No. U-17032. 21


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Q. Has Staff previously addressed the position advocated by Mr. Revere in this case that a 1

utility’s production cost should be reduced by the 25% which is allocated on the basis of 2

energy usage for purposes of determining a capacity charge to apply to ROA customers 3

who take capacity service from the utility? 4

A. Yes. Staff directly addressed and opposed this position in response to an argument made 5

by Energy Michigan in Case No. U-17032. My Exhibit A-18 (JCA-6) is Exhibit EM-6 6

from Case No. U-17032, which consists of Staff witness Janssen’s Discovery Response 7

No. 1 to Energy Michigan’s First Discovery Request in that case (see 3 TR 409-410 in 8

Case No. U-17032 for Ms. Janssen’s testimony authenticating that exhibit.) That exhibit 9

shows Ms. Janssen’s explanation that the COSS, which is the basis for the capacity 10

charges supported by her in Case No. U-17032, utilizes the 75/25 weighting methodology 11

to allocate production costs. However, although the COSS upon which Staff’s proposed 12

capacity charges in Case No. U-17032 used the same cost allocation methodology for 13

production costs than the one used in this case, Ms. Janssen did not propose reducing the 14

costs included in the capacity charge by the 25% which represents the portion of costs 15

allocated based on energy. In its Reply Brief filed in Case No. U-17032 (pages 33 and 16

34), Staff rejected the argument that capacity costs should be reduced by the 25% 17

energy-based allocation of those costs, stating as follows (emphasis added): 18

“Energy Michigan correctly states that Michigan ratemaking 19 principles require that all legitimate capacity costs be allocated 20 75% on the basis of demand and 25% on the basis of energy. . . . 21 Based on this fact, Energy Michigan asserts that since OAD 22 customers do not use any of I&M’s energy it is inappropriate to 23 allocate any of the capacity costs based on energy allocator; and as 24 such, the capacity costs allocated to OAD customers should be 25 reduced by 25%. This is a complete mischaracterization of how 26 cost allocation occurs. 27


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“The methodology of allocating capacity costs based on 75% 1 demand and 25% energy has nothing to do with allocating energy 2 costs to OAD customers. There are no energy costs being 3 allocated to OAD customers under the methodology recommended 4 by Staff and the Company. If the capacity costs for OAD 5 customers were reduced by 25% then OAD customers would 6 only be paying for 75% of the capacity costs. 3 TR 405-406 7 [citing Ms. Janssen’s testimony]. This would not create cost 8 based rates. 9

“Allocating capacity costs based on 75% demand and 25% energy 10 is simply a way to fairly allocate capacity costs between the 11 various customer classes. While no one methodology is perfect for 12 allocating the exact costs to the customer that causes them, it is 13 still necessary to choose a method that accurately and fairly 14 allocates cost to classes so that similar customers are charged the 15 same price for the same service. This helps to ensure that the 16 Company can collect its revenue requirement in total. I&M and 17 Staff’s proposal accomplish both of these tasks, while Energy 18 Michigan’s proposal accomplishes neither of these functions. If 19 Energy Michigan’s proposal is approved, OAD customers will pay 20 less than full service customers . . .” 21

Mr. Revere’s direct testimony in the instant case is directly contrary to Staff’s statements 22

and positions made in Case No. U-17032. 23

Q. Has the Commission considered the argument put forth by Mr. Revere that a capacity 24

charge for capacity service provided to ROA customers should be reduced by 25% as a 25

result of the 75/25 allocator? 26

A. Yes, in its September 25, 2012 Order in Case No. U-17032 (page 30), the Commission 27

rejected Energy Michigan’s argument that capacity costs should be reduced by 25% to 28

account for the energy allocator. In that case, the Commission found that “if the capacity 29

rate is reduced by 25% as recommended by Energy Michigan, OAD customers will only 30

be paying for 75% of capacity costs, while standard service customers will pay 100%. 31

Such ratemaking is discriminatory and inconsistent with Michigan ratemaking 32

principles.” 33


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Q. Did any other Staff witness support the embedded cost-of-service ratemaking 1

methodology for determining a capacity charge to apply to ROA and bundled service 2

customers in Case No. U-17032? 3

A. Yes. Staff witness William M. Stosik also supported the embedded cost-of-service 4

ratemaking methodology proposed by I&M and advocated by Staff witness Janssen, 5

which is not consistent with the position taken by Staff witness Revere in the instant case. 6

In response to intervenor testimony alleging that an embedded cost-of-service-based 7

methodology for determining a capacity charge to apply for I&M’s capacity service 8

provided for OAD load was anticompetitive, Mr. Stosik testified: 9

“A cost of service based mechanism cannot be anticompetitive 10 because it is based on the Company’s cost of providing service. In 11 its order dated May 24, 2012 in this proceeding, the Commission 12 ordered I&M to file a cost of service based proposal for the 13 creation of a state compensation mechanism for electric supplier 14 capacity in its Michigan territory. The Commission further 15 ordered that the proposal adhere to Michigan-specific ratemaking 16 principles. Staff witness Bonnie Janssen presented direct 17 testimony in this proceeding indicating that Staff agrees (except for 18 some minor adjustments) with the state compensation mechanism 19 proposal filed by I&M and that I&M’s proposed approach is 20 reasonable. Thus, I&M’s Proposed Capacity Pricing cannot be 21 considered anticompetitive since it is based on cost of service. In 22 fact, the opposite is true. Establishing a cost of service based 23 mechanism ensures that both groups of customers (choice and non-24 choice) pay the same price for the capacity that I&M is required to 25 make available to both groups of customers pursuant to its Fixed 26 Resource Requirement (FRR) obligation.2 Taken another step 27 further, if the two groups of customers were to pay different 28 amounts for the same I&M capacity then one group would be 29 disadvantaged while the other group would benefit. If the capacity 30 compensation mechanism is set above the cost of service then the 31 utility (and/or PSCR customer) would benefit while the AES 32 (and/or choice customer) would be disadvantaged, whereas if the 33

2 The Fixed Resource Requirement obligation under the PJM Interconnection, LLC construct is analogous to Consumers Energy’s obligation to provide capacity service to ROA customers whose alternative energy suppliers fail to demonstrate sufficient capacity pursuant to the SRM under Section 6w of Act 341.


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capacity mechanism is set below the cost of service then the AES 1 (and/or choice customer) would benefit while the utility (and/or 2 PSCR customer) would be disadvantaged.” MPSC Case No. 3 U-17032, 3 TR 380-381, footnote added. 4

Q. Did Staff witness Revere make any other proposal to determine the cost of capacity? 5

A. Yes, at page 5 of his direct testimony, Staff witness Revere opines that the proper cost of 6

capacity is the Cost of New Entry or the cost to build a Combustion Turbine (“CT”). 7

A. Are these alternative proposals consistent with Staff’s accepted definition of “Capacity 8

Power Supply” in Case No. U-17032? 9

A. No, they are not. The definition of “Capacity Power Supply” adopted by Staff witness 10

Janssen in Case No. U-17032 is an appropriate definition which reflects the capacity 11

resources, and associated costs, which are necessary to provide capacity service to both 12

bundled and ROA customers whose loads the utility becomes obligated to serve pursuant 13

to the SRM. As addressed by Company witness David F. Ronk, Jr., Mr. Revere’s chosen 14

definition in the instant proceeding encompasses only incremental capacity, and not the 15

entire portfolio of utility capacity necessary to provide capacity service to the load for 16

which it is obligated to serve, which includes ROA load for which the utility is obligated 17

to provide capacity pursuant to the SRM. 18

Q. Is Case No. U-17032 distinguishable from the instant case based on the fact that I&M’s 19

Michigan service territory is part of the PJM Interconnection, LLC (“PJM”) and not part 20

of the wholesale market governed by the Midcontinent Independent System Operator, 21

Inc.? 22

A. No, that distinction is not meaningful to the establishment of a retail capacity charge 23

which compensates a utility for capacity service provided to ROA customers in Michigan 24

pursuant to the SRM. Case No. U-17032 involved the Commission’s consideration and 25


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establishment of an SCM capacity charge for I&M to apply to ROA load for whom I&M 1

had an obligation to provide capacity service. That is the same intent and purpose of the 2

SRM capacity charge, and the positions taken by Staff in Case No. U-17032 are 3

consistent with the appropriate methodology to determine the SRM capacity charge to 4

apply to ROA load for whom Consumers Energy becomes obligated to provide capacity 5

service. The positions taken by Staff witness Revere in the instant case are inconsistent 6

with Staff’s positions set forth in Case No. U-17032, which were adopted by the 7

Commission in its September 22, 2012 Order in that case. 8

Rebuttal To CNE Witness Makholm 9

Q. How do you respond to CNE witness Makholm when disagreeing with the methodology 10

used by the Company to identify its capacity-related costs on his direct testimony, 11

page 11, lines 4 through 14? 12

A. As explained in my rebuttal to Staff witness Revere, the Company followed the 13

methodologies supported by NARUC and the Commission’s previously-approved Case 14

No. U-17032, which are consistent with the approach used by the Company in this case. 15

Q. Do you agree with Mr. Makholm at page 11, line 20 through page 12, line 2, that Act 341 16

“describe[s] in detail how to tie the SRM capacity charge to those forward-looking, 17

forecasted costs that would apply to AES load”? 18

A. No. Act 341 provides that the SRM capacity charge should include “the capacity-related 19

generation costs included in the utility’s base rates, surcharges, and power supply cost 20

recovery factors.” (MCL 460.6w(3).) The Company has relied on well-accepted 21

definitions of capacity costs, cost-of-service principles and Commission-approved 22

methodologies for the calculation of these costs as previously described. 23


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Q. Is it appropriate to accept Mr. Makholm’s recommendation for the Company to change 1

its production allocation from the 75/25 to the Average and Excess methodology for the 2

calculation of the SRM capacity charge? 3

A. No. Changing the production allocation is an issue that would need to be addressed in a 4

general rate case proceeding. Any attempt to calculate the SRM capacity charge 5

differently for ROA customers than bundled service customers would not comply with 6

the Act 341 requirement to “ensure that the resulting capacity charge does not differ for 7

full service load and alternative electric supplier load” (Section 6w (3)). 8

Rebuttal To ABATE Witness Dauphinais 9

Q. Do you agree with Mr. Dauphinais’ concern on his direct testimony, page 16, lines 17 10

through 20, about the inappropriate classification of the 25% total energy allocation of 11

fixed production costs to capacity-related costs? 12

A. No, I do not. The Company’s proposal is well substantiated in the NARUC manual and 13

supported by previous Commission orders as detailed in my rebuttal to Staff witness 14

Revere. 15

Q. At page 21, lines 2 through 9 of his direct testimony, Mr. Dauphinais recommends that 16

the Commission require Consumers Energy to revise its classification between capacity- 17

and non-capacity-related costs such that the 25% of fixed production costs, which is 18

allocated on an annual total energy usage basis, is classified as non-capacity-related 19

production cost. Mr. Dauphinais states that “[t]his would recognize that this energy 20

allocated cost is not associated with providing resource adequacy and is instead 21

associated with providing energy costs savings to bundled retail customers or instead 22

associated with recovery of other legacy costs not associated with providing resource 23


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adequacy.” Is Mr. Dauphinais’ recommendation or support for this recommendation 1

appropriate? 2

A. No. As explained in my rebuttal to Staff, the Company’s definition of capacity-related 3

costs is consistent with established Michigan ratemaking practice and industry practice. 4

Q. Did Mr. Dauphinais specify the portion of Consumers Energy’s fixed production costs 5

which he claims is “associated with providing energy costs savings to bundled 6

customers” and not resource adequacy? 7

A. Although Consumers Energy asked Mr. Dauphinais to specify the amount of the 8

Company’s fixed production costs which are allocated on a 25% energy usage basis 9

which are “associated with providing energy costs savings to bundled customers” and not 10

resource adequacy, he was unable to do so. See my Exhibit A-19 (JCA-7), which is 11

Mr. Dauphinais’ response to Discovery Request No. 18239-CE-AB-9 (see, specifically, 12

subpart (a) of that discovery response). Instead of providing a specific explanation of his 13

claim, he instead generally asserted that it is his “position that any of Consumers 14

Energy’s fixed production costs, which on a per-unit basis exceed the per-unit amortized 15

cost of new entity [sic—he presumably means “entry”] for a frame simple cycle 16

combustion turbine generator facility, are either associated with providing energy cost 17

savings to bundled customers or are associated with the recovery of other legacy costs.” 18

As explained by Company witness Ronk, Consumers Energy’s entire generating 19

fleet is used to provide resource adequacy. Mr. Dauphinais’ assumption that the 20

resources associated with the fixed production costs allocated on an energy basis are not 21

used to provide capacity (i.e. resource adequacy) is inconsistent with how the Company 22


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provides capacity service and with accepted ratemaking practice, and for these reasons it 1

should be rejected. 2

Q. Did Mr. Dauphinais specify the amount included in the Company’s fixed production cost 3

allocated on a 25% energy usage basis which he believes is “associated with recovery of 4

other legacy costs not associated with providing resource adequacy”? 5

A. No, he did not. In his response to Discovery Request No. 18239-CE-AB-9 (specifically 6

subpart (c)), Mr. Dauphinais defined “other legacy costs” (as that term is used in his 7

testimony) as costs which “include, but are not limited to, generational differences in the 8

cost of construction of generation capacity, past poor investment decisions and 9

subsequent capital investments in environmental controls.” See my Exhibit A-19 10

(JCA-7) for Mr. Dauphinais’ explanation of his use of the term “legacy costs.” 11

Q. The term “legacy costs” is sometimes used in the description of a utility’s stranded costs. 12

However, Section 6w(3)(b) of Act 341 requires that all non-capacity-related electric 13

generation costs including, but not limited to, costs previously set for recovery through 14

net stranded cost recovery and securitization, as well as certain net revenues of energy 15

sales, be excluded from the SRM capacity charge. Do the costs included in the 16

Company’s SRM capacity charge in this proceeding include any costs previously set for 17

recovery through stranded cost recovery or securitization? 18

A. No, they do not. The costs associated with the Company’s stranded costs and 19

securitization filings were not included in the capacity related costs identified by me for 20

purposes of establishing the SRM capacity charge in this case. 21


rte0817-jca 17

Q. Please describe the nature of Consumers Energy’s previous stranded cost recovery. 1

A. Stranded costs were approved in Case Nos. U-13720 (2002 costs) and U-14098 (2003 2

costs) totaling $63 million. This $63 million represented a fixed generation cost revenue 3

requirement (depreciation, taxes, interest, etc.) for the years 2002 and 2003 when rates 4

were frozen. This amount represented only annual expenses incurred by the Company in 5

those two years which were not being recovered through general rates because rates were 6

frozen at that time. Interest was recorded over time until collection of the regulatory 7

asset was complete. 8

Collection began for the stranded cost surcharge beginning in 2004 and ending in 9

2012. 10

When collection began (initially from ROA customers only) back in 2004, the 11

stranded costs balance continued to increase as interest exceeded the amount of annual 12

collections from ROA customers. In Case No. U-15744, the Commission ordered the 13

Company to begin collection from non-residential full service customers, as well as ROA 14

customers, to accelerate collection of the stranded cost balance (which at the time was 15

slightly over $71 million) to comply with Michigan statutes that specified a collection 16

deadline. Over the entire collection period (2004 through 2012), non-residential full 17

service customers ended up paying for approximately $55 million of the total stranded 18

costs. See my Exhibit A-20 (JCA-8), which details the amounts of revenue received by 19

Consumers Energy from stranded cost surcharges, per year. 20


rte0817-jca 18

Q. Has Consumers Energy included the SRM capacity charge costs which are associated 1

with resources that are no longer used to provide capacity resource adequacy to 2

customers? 3

A. No. 4

Rebuttal To Energy Michigan Witness Zakem 5

Q. At page 23 of his direct testimony, Mr. Zakem stated that “Consumers’ testimony does 6

not consider the cost-of-service statute in calculating its proposed SRM charge.” Do you 7

agree with his statement? 8

A. No. The Company has fully relied on its COSS to calculate the SRM capacity charge as 9

shown on my Exhibit A-2 (JCA-2). 10

Q. How do you address Mr. Zakem’s concern, at page 25 of his direct testimony, that 11

Act 341 Section 6w does not define capacity-related costs, in addition to his proposal to 12

exclude 25% of demand-related production costs from the calculation? 13

A. While Act 341 provides that the SRM capacity charge must “include the capacity-related 14


recovery factors,” the Commission has previously adopted the definition of 16

capacity-related costs used by the Company in this case in Case No. U-17032. This 17

definition is shown in my Exhibit A-16 (JCA-4). In addition, my rebuttal to Staff witness 18

Revere explains why it is inappropriate to classify production costs as energy-related 19

based on its energy weighting allocation component. 20

Q. Does this conclude your rebuttal testimony? 21

A. Yes, it does. 22




)

EXHIBITS

OF

JOSNELLY C. APONTE

ON BEHALF OF


August 2017

Case No. U-17032

Exhibit S-2 (BJ-2)

Witness: Bonnie Janssen

STATE OF MICHIGAN


________________________________________________________________________

In the matter, on the Commission’s own motion )

to initiate a proceeding to establish a state )

compensation mechanism for alternative electric )

supplier capacity in INDIANA MICHIGAN ) Case No. U-17032

POWER COMPANY’s Michigan service territory )

__________________________________________)

Indiana Michigan Power Company (I&M) hereby submits the following Audit

Responses:

Request No.: BJ-02

Auditor: Janssen, B.

MPSC Audit Request

1. Please provide a definition of Capacity Power Supply.

Response:

Capacity Power Supply charges are the retail power supply charges for costs incurred by

I&M in order to meet its customers' capacity needs.

Capacity represents the need to have adequate generating resources to ensure that the

demand for electricity can be met at all times. A utility or other supplier is required to

have the resources to meet its customers’ demand plus a reserve amount.

2. Please provide a definition of Non-Capacity Power Supply.

Response:

Non-Capacity Power Supply charges are the retail power supply charges for generation

and transmission costs that are not included as Capacity Power Supply charges.

Case No.: U-18239 Exhibit: A-16 (JCA-4)

Witness: JCAponte Date: August 2017

Page 1 of 1

MICHIGAN PUBLIC SERVICE COMMISSIONConsumers Energy Company

MPSC Staff’s Answer to Consumers’ Third Discovery Request MPSC Case No. U-18239 August 2, 2017

1

18239-CE-ST-5. Please reference page 6, lines 14-19 of Staff witness Nicholas M.

Revere’s testimony in this proceeding, and his Exhibit S-1.1.

a. Please explain how Staff identified the costs in the Cost ofService Study which are capacity-related.

b. Please provide all documents used or consulted in the referencedStaff identification of costs in the Cost of Service Study whichare capacity-related.

c. Please provide copies of all communications which address,discuss, or relate to the referenced Staff identification of costs inthe Cost of Service Study which are capacity-related.

Please provide a definition of non-capacity power supply.

Answer

Please provide a definition of non-capacity power supply.

a. As stated by Staff witness Revere on page 6, line 21 – page 7,line 3:Staff identified all costs currently allocated using the productioncost allocator (with the exception of fuel handling costs whichare more properly considered energy costs, as the Company didin its initial filing). The current production cost allocator of 4CP(four coincident peak) 75-25 effectively recognizes that 75% ofcosts so allocated are capacity-related. Therefore, Staff split thecosts currently allocated by the production allocator intocapacity- and non-capacity-related portions, using the 75-25split.

b. Cost of Service Study which are capacity-related. Staff is awareof no such documents.

c. Staff objects to the question to the extent that is asks forcommunications covered either by the attorney client privilege,or the attorney work product privilege. Staff witness Revereattended several meetings with other Staff and Staff’s attorneys,which included responsive communications, but which are alsoprotected by the attorney client privilege and the attorney workproduct privilege. Staff witness Revere also sent acommunication to other Staff and Staff’s attorneys, whichincluded responsive communications, which is protected by the

Case No.: U-18239Exhibit: A-17 (JCA-5)

Witness: JCAponteDate: August 2017

Page 1 of 2



2

attorney client privilege and the attorney work product privilege. Staff witness Revere also received a communication from Staff’s attorneys, which included responsive communications, but which is also protected by the attorney client privilege and attorney work product privilege.

In further answer and without waiving the objection, in addition to the

communications previously listed, Staff witness Revere recalls discussing his

proposal with Ron Ancona, Paul Proudfoot, and Daniel Blair. These conversations

amounted to Staff witness Revere and the other parties discussing ways to refine

particular parts of the proposal, as well as general feedback. The proposal was not

significantly changed as a result of these conversations. Non-privileged responsive

documents are attached hereto.

Respondent: Nicholas M. Revere As to objections:

Lauren D. Donofrio Assistant Attorney General MPSC Staff



Page 2 of 2

MPSC Staffs Answer to Energy Michigan, Inc.'s First Discovery Request MPSC Case No. U-17032

Question

For Bonnie Janssen:

1. Please describe the cost allocation mechanism in the Cost of Service study that is the basis for the rates proposed in your Testimony. In that description, please specify the percent of the production related costs allocated by peak demand, the percentage allocated by on-peak energy use, and the percentage allocated by total energy use.

Answer

1. The basis for the cost allocation mechanism in I&M's Cost of Service Study(COSS) can be found in the testimony submitted in I&M's previous rate cases, specifically MPSC Case Nos. U-16180 and U-16810. For further information on the COSS, refer to I&M witness David Roush's testimony, in Case No. U -16180, pages 7-18, which utilized a 2010 test year, http://efile.mpsc.state.mi.us/efile/docs/16180/0003.pdf; and refer to I&M witness Nancy Heimberger's testimony, in Case No. U-16801, pages 9-15, which utilized a 2012 test year, http://efile.mpsc.state.mi.us/efile/docs/16801/0003.pdf. In I&M's last two rate cases, Staff agreed with the Company's proposed cost of service study, as reference in my testimony in both cases. See http://efile. mpsc.sta te .mi. us/efile/docs/16180/0061.pdf and http://efile. mpsc.sta te. mi. us/efile/docs/16801/0039.pdf.

I&M filed its COSS pursuant to the Commission's guidelines established in Case No. U-4771. Since I&M has approximately 130,000 Michigan customers, it is not required to follow the 50-25-25 COSS specific requirements for the larger utilities as specified in PA 286.

The apportionment methods shall consist of the following as set in the Case No. U-4771 guidelines:

1. Average 12 monthly peak demands.

2. Production and transmission plant assigned as 75% demandrelated and 25% energy-related.

3. Specific distribution plant, such as meters and service drops, used exclusively for a given customer shall be treated as

2



Page 1 of 2


MPSC Staffs Answer to Energy Michigan, Inc.'s First Discovery Request MPSC Case No. U-17032

customer-related. All other distribution plant shall be treated as demand-related.

Prior to following the above-specified apportionment method, I&M costs must first be separated into the three jurisdictions: Indiana, Michigan, and FERC (wholesale). The jurisdictional separation study (JSS) apportions the production and transmission to the three entities as 100% demand-related. From that JSS, the Michigan costs and revenues are further separated in the COSS. Within the COSS, the production and transmission costs are apportioned as 75% demand-related and 25% energy-related.

Respondent: Bonnie J ansscn

3



Page 2 of 2

216068894.1 07411/312567

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION* * * * *

In the matter, on the Commission’s own motion,to open a docket to implement the provisions ofSection 6w of 2016 PA 341 forCONSUMERS ENERGY COMPANY’Sservice territory.

))))))

Case No. U-18239

ALJ Mark D. Eyster

ASSOCIATION OF BUSINESSES ADVOCATING TARIFF EQUITY,RESPONSE TO CONSUMERS ENERGY COMPANY’S

FOURTH DISCOVERY REQUESTS

The Association of Businesses Advocating Tariff Equity (“ABATE”), by its attorneys,

Clark Hill PLC, submit the following response to Consumers Energy Company’s (“CECo” or the

“Company”) first data requests to the Association of Businesses Advocating Tariff Equity.

Request No. 18329-CE-AB-9:

Please reference page 21, lines 2 through 9 of ABATE witness James R.

Dauphinais’ testimony.

a. Please specify the amount of Consumers Energy’s production cost

which is allocated on an annual total energy usage basis which “is not

associated with providing resource adequacy and is instead associated

with providing energy costs savings to bundled retail customers.”

b. Please specify the amount of Consumers Energy’s production cost

which is allocated on an annual total energy usage basis which is

“associated with recovery of other legacy costs not associated with

providing resource adequacy.”



Page 1 of 4


216068894.1 07411/312567

c. Please define “other legacy costs” as used on line 8, page 21 of Mr.

Dauphinais’ testimony.

Response:

a. Mr. Dauphinais has not precisely determined which portion of

Consumers’ production cost which is allocated on an annual total

energy usage basis is associated with providing energy cost savings to

bundled retail customers versus being associated with recovery of

other legacy costs not associated with providing resource adequacy.

However, it is Mr. Dauphinais’ position that all of Consumers’ fixed

production costs that on a per unit basis exceed the per unit amortized

cost of new entity for a frame simple cycle combustion turbine

generator facility are either associated with providing energy cost

savings to bundled retail customers or are associated with recovery of

other legacy costs. In addition, it is Mr. Dauphinais’ position that no

more than all of the portion of Consumers’ production cost which is

allocated on an annual total energy usage basis is associated with

providing energy cost savings to bundled retail customers.

b. Please see the response to a.

c. Mr. Dauphinais defines other legacy costs to include, but not

necessarily limited to, generational differences in the cost of

construction of generation capacity, past poor investment decisions

and subsequent capital investment in environmental controls. In

general, it is Mr. Dauphinais’ position that all of Consumers’ fixed



Page 2 of 4

216068894.1 07411/312567

production costs on a per unit basis that are in excess of Consumers’

per unit additional cost (i.e., incremental cost) to provide capacity to

ROA customers paying the SRM Capacity Charge are legacy costs not

associated with providing resource adequacy for those ROA

customers. A portion of those legacy costs are associated with

providing energy cost savings to bundled retail customers. The

remainder of those legacy costs are what Mr. Dauphinais refers to as

“other legacy costs.”



Page 3 of 4

216068894.1 07411/312567

Respectfully submitted,

CLARK HILL PLC

By: ____________________________________Michael J. Pattwell (P72419)Sean P. Gallagher (P73108)Stephen A. Campbell (P76684)Attorneys for Association of BusinessesAdvocating Tariff Equity212 East Grand River AvenueLansing, Michigan 48906Office: [email protected]@clarkhill.com

Date: August 4, 2017

Digitally signed by: Michael J. PattwellDN: CN = Michael J. Pattwell email = [email protected] C = US O = Clark Hill, PLCDate: 2017.08.04 13:36:29 -05'00'

Michael J. Pattwell



Page 4 of 4




Page 1 of 1

Consumers Energy CompanyStranded Cost Surcharge Collections

2004 - 2012

Bundled ROAComm Indust Interdept. Total Bundled Comm Indust Total ROA Total

2004 -$ -$ -$ -$ 134,401$ 286,504$ 420,905$ 420,905$ 2005 0 0 0 0 1,605,224 3,045,036 4,650,260 4,650,2602006 0 0 0 0 598,592 1,353,602 1,952,194 1,952,1942007 0 0 0 0 566,917 1,039,896 1,606,813 1,606,8132008 0 0 0 0 736,353 1,101,181 1,837,534 1,837,5342009 3,305,334 2,335,505 13,387 5,654,226 1,268,122 2,200,945 3,469,067 9,123,2932010 9,901,438 6,617,551 41,230 16,560,219 2,376,406 5,942,877 8,319,283 24,879,5022011 9,703,835 6,689,534 38,197 16,431,566 2,277,061 5,944,751 8,221,812 24,653,3782012 9,737,257 6,953,251 37,216 16,727,724 2,267,319 6,137,761 8,405,080 25,132,804

32,647,864$ 22,595,841$ 130,030$ 55,373,735$ 11,830,395$ 27,052,553$ 38,882,948$ 94,256,683$




)

REBUTTAL TESTIMONY

OF

LAURA M. COLLINS

ON BEHALF OF


August 2017

LAURA M. COLLINS REBUTTAL TESTIMONY

rte0817-lmc 1


A. My name is Laura M. Collins, and my business address is One Energy Plaza, Jackson, 2

Michigan 49201. 3

Q. Are you the same Laura M. Collins who previously filed direct testimony in this 4

proceeding on behalf of Consumers Energy Company (“Consumers Energy” or the 5

“Company”)? 6

A. Yes. 7

Q. What is the purpose of your rebuttal testimony? 8

A. I will rebut certain rate design positions of the Michigan Public Service Commission 9

(”MPSC” or the “Commission”) Staff (“Staff”) witness Nicholas M. Revere, Association 10

of Businesses Advocating Tariff Equity (“ABATE”) witness James R. Dauphinais, and 11

Constellation NewEnergy, Inc. (“CNE”) witness Jeff D. Makholm. 12

Q. Are you sponsoring any rebuttal exhibits? 13

A. No. 14

Staff Witness Revere 15

Q. Staff witness Revere states that if the Commission interprets Section 6w(3) of Public Act 16

341 (“Act 341”) to mean that a single identical charge is required to be paid by all 17

customers of a utility, then capacity related costs should be collected through summer 18

on-peak kWh charges for rate schedules without demand charges and through summer 19

on-peak kW charges for rate schedules with demand charges. Do you agree with this? 20

A. No. Section 6w(3) of Act 341 sets forth direction to “ensure that the resulting capacity 21

charge does not differ for full service load and alternative electric supplier load.” Full 22

service customers pay for capacity year round, not just in the summer. Applying the 23


rte0817-lmc 2

State Reliability Mechanism (“SRM”) capacity charge as a summer-only charge would 1

mean that full-service customers pay for capacity on a year-round basis, whereas Retail 2

Open Access (“ROA”) customers who pay the SRM capacity charge would not. The 3

SRM capacity charge would therefore differ for full service load and Alternative Electric 4

Supplier (“AES”) load. The application of a capacity charge on a year-round basis for 5

full-service and SRM capacity charge customers would be consistent with the law’s 6

requirement quoted above. In addition, the year-round application appropriately 7

recognizes the fact that utility capacity service is provided all year-round, and not only at 8

summer peak periods. Mr. Revere’s proposal to establish a summer-only SRM capacity 9

charge should be rejected. 10

Q. In regards to prorating capacity charges for AES customers, Staff witness Revere states 11

that this capability should already exist in the Company’s system as it happens any time 12

an order comes out changing rates. Do you agree with Mr. Revere? 13

A. No. Consumers Energy’s billing system is currently designed to prorate rates on a 14

service on, and after, basis when new rates are issued, where the proration is applied to 15

all customers based on the date of the change. The proration Mr. Revere is suggesting 16

would be customer specific based on the AES serving the ROA customer. It is possible 17

that our billing system could be configured to accommodate this type of proration, but 18

such configuration does not exist in the system today and would take time and resources 19

to make such a configuration operational. 20


rte0817-lmc 3

Q. Mr. Revere proposes that any mismatches between capacity costs incurred in a given 1

year, and collected in the year, be addressed in the Power Supply Cost Recovery 2

(“PSCR”) Reconciliation process and thus there is no need to change the capacity portion 3

of the PSCR factor monthly. Do you agree with Mr. Revere? 4

A. No. While I agree that the differences in the actual PSCR capacity costs and collections 5

will be reconciled in a PSCR Reconciliation case, it is important for the PSCR factor to 6

be adjusted monthly to reflect the incremental changes in capacity as they occur. This 7

better reflects timely rate recovery and recovers capacity from SRM customers in the 8

same manner the Company recovers capacity from all other customers. 9

CNE Witness Makholm 10

Q. CNE witness Makholm has proposed calculating the SRM charge based on the “Average 11

and Excess” method. Do you agree with his proposal? 12

A. As stated above, in accordance with Section 6W(3) of Act 341, the SRM capacity charge 13

should not differ for full service load and the AES load, which is subject to the SRM 14

capacity charge. The Company’s full service customers do not pay for capacity today 15

based on the “Average and Excess” method. The Company has proposed SRM capacity 16

charges that mirror the capacity charges that full service customers pay. 17

ABATE Witness Dauphinais 18

Q. ABATE witness Dauphinais has proposed the creation of a demand charge for recovery 19

of transmission costs. Do you agree with his proposal? 20

A. No. Consumers Energy assigned transmission costs as non-capacity costs for purposes of 21

establishing the SRM capacity charge in this case. Designing a separate transmission 22


rte0817-lmc 4

demand charge that would appear in a separate line on the customer’s monthly electric 1

invoice is an issue that is best addressed in a general rate case proceeding. 2

Q. Mr. Dauphinais recommends that Consumers Energy update its SRM Capacity charge for 3

ROA customer SRM Capacity Charge billing units and Consumers Energy’s incremental 4

cost to provide capacity to those customers once the February 2018 AES capacity 5

demonstrations have been made. Do you agree with this proposal? 6

A. No. The Company agrees that to the extent it is known what ROA customers will pay the 7

SRM charge, their billing units and associated revenue should be included in the 8

development of the capacity charges all customers pay. However, since this has an 9

impact on all customer rates, this would need to be done in a general rate case or other 10

fully contested proceeding. 11

Q. Mr. Dauphinais has recommended that the true-up costs for capacity-related costs that 12

flow through the PSCR Capacity Factor be allocated to classes on a 100% demand 13

4 Coincident Peak basis and that the PSCR Capacity Factor be a class differentiated 14

demand charge that appropriately accounts for loss differences between the retail classes. 15

Do you agree with this recommendation? 16

A. No. The PSCR factor is currently calculated as a uniform factor to all customers and is 17

reconciled annually. If a different factor is calculated for each rate class, that would need 18

to be approved in a PSCR Plan case. 19


A. Yes. 21



In the matter, on the Commission’s own motion, ) to open a docket to implement the provisions of ) Section 6w of 2016 PA 341 for ) Case No. U-18239 CONSUMERS ENERGY COMPANY’S ) service territory. ) )

REBUTTAL TESTIMONY

OF

DAVID F. RONK, JR.

ON BEHALF OF


August 2017

DAVID F. RONK, JR. REBUTTAL TESTIMONY

rte0817-dfr 1


A. My name David F. Ronk, Jr., and my business address is 1945 West Parnall Road, 2

Jackson, Michigan 49201. 3

Q. Are you the same David F. Ronk, Jr. who submitted direct testimony in this case on 4

behalf of Consumers Energy Company (“Consumers Energy” or the “Company”)? 5

A. Yes. 6

Q. What is the purpose of your rebuttal testimony? 7

A. The purpose of my rebuttal testimony is to address certain issues raised in the direct 8

testimony of the following Michigan Public Service Commission (“MPSC” or the 9

“Commission”) Staff (“Staff”) and other intervenors in this case: 10

• Eric W. Stocking, Staff; 11

• Heather A. Cantin, Staff; 12

• Nicolas M. Revere, Staff; 13

• James R. Dauphinais, Association of Businesses Advocating Tariff Equity 14 (“ABATE”); 15

• Jeff D. Makholm, Ph.D., Constellation NewEnergy (“CNE”); 16

• Lael E. Campbell, Energy Michigan, Inc. (“Energy Michigan”); 17

• Rupert R. Jennings, Energy Michigan; and 18

• Alexander J. Zakem, Energy Michigan. 19

Those issues include: (1) the State Reliability Mechanism (“SRM”) capacity charge; 20

(2) utility capacity planning; (3) marginal cost-based ratemaking; (4) assessment of the 21

SRM capacity charge to Alternative Energy Suppliers (“AESs”); (5) the Cost of New 22

Entry (“CONE”) as a proxy, or cap, for the SRM capacity charge; (6) the 30-year term of 23

the SRM capacity charge; (7) the Retail Open Access (“ROA”) 10% cap; (8) market 24


rte0817-dfr 2

energy sales; (9) the proration of the SRM capacity charge among customers; (10) a 1

proposal to require the 2018 SRM capacity charge to be updated; (11) the duration of the 2

SRM; (12) capacity-related generation costs; (13) the alleged right of ROA customers to 3

elect to incur the SRM capacity charge; (14) a proposal to allow AES billing of the SRM 4

capacity charge; (15) explanations of the Midcontinent Independent System Operator, 5

Inc. (“MISO”) capacity rules; (16) Energy Michigan’s alternative proposal; 6

(17) provision of energy separate from capacity; (18) peak load contribution; 7

(19) sufficiency of capacity to achieve the Local Clearing Requirement (“LCR”); (20) the 8

2016 Public Act 341 (“Act 341”) construct; (21) Energy Michigan’s evaluation of the 9

MISO capacity situation; (22) the federal role in ensuring resource adequacy; and (23) 10

the SRM term length as it relates to the MISO Tariff. 11

Q. Are you sponsoring any rebuttal exhibits? 12

A. I am sponsoring the following exhibits: 13

Exhibit A-21 (DFR-5) Testimony of Lawrence J. Makovich before the 14 Michigan Senate Energy and Technology 15 Committee, September 17, 2015; 16

Exhibit A-22 (DFR-6) ABATE’s Responses to Consumers Energy’s 17 Second Discovery Requests, dated July 31, 2017; 18

Exhibit A-23 (DFR-7) 2017 MISO OMS Resource Adequacy Survey 19 Results Report, dated June 2017; 20

Exhibit A-24 (DFR-8) Staff Responses 18239-CE-ST-6 and 18239-CE-ST-21 7 to Consumers Energy’s Third Discovery 22 Requests, dated August 2, 2017; and 23

Exhibit A-25 (DFR-9) ABATE’s Response 18239-CE-AB-11 to 24 Consumers Energy’s Fourth Discovery Request, 25 dated August 4, 2017. 26

Q. Were these exhibits prepared by you or under your supervision? 27

A. Yes, they were. 28


rte0817-dfr 3

STATE RELIABILITY MECHANISM CAPACITY CHARGE 1

Q. What testimony do you rebut regarding the SRM capacity charge? 2

A. Several witnesses opine on the intent of Act 341 in establishing an SRM capacity charge. 3

The testimony of Mr. Makholm, Mr. Revere, and Mr. Dauphinais provide a view that is 4

contrary to the terms and intent underlying Act 341. 5

Q. How does Mr. Makholm define the problem that Section 6w of Act 341 seeks to remedy? 6

A. On page 11 of Mr. Makholm’s testimony, beginning at line 6, he states the purpose of 7

Section 6w “is to establish a ‘cost-effective, reasonable, and prudent’ mechanism to 8

ensure reliability. The legislation seeks to ensure sufficient capacity resources at the 9

‘forecasted coincident peak demand’ plus a reserve margin.” Mr. Makholm uses this 10

premise to criticize Consumers Energy’s proposed capacity charge for being “made up of 11

the entirety of its non-variable costs unrelated to any measure of peak reliability, as 12

such.” 13

Q. Is Mr. Makholm’s characterization of Section 6w accurate? 14

A. Not entirely. Mr. Makholm asserts that Section 6w is only intended to secure enough 15

incremental new capacity in the future to maintain reliability in Michigan. While 16

Consumers Energy certainly agrees that incremental new capacity will be needed in the 17

future, that was not the only issue that Section 6w addresses. Section 6w also provides 18

that all customers in Michigan, both bundled utility customers and ROA customers, 19

whose suppliers fail to provide adequate capacity resources, pay the same rate for 20

capacity at the time the utility provides capacity resources on their behalf. That is, the 21

current fleet of capacity resources in Michigan is required on a continuing basis to meet 22

reliability needs as service is provided, and the purpose of Section 6w is to ensure that all 23


rte0817-dfr 4

customers either provide or pay an equitable share for the capacity service provided by 1

that fleet at the time service is provided. For customers paying the utility to provide 2

capacity, the rates for capacity are required to be the same for bundled and ROA 3

customers alike. 4

Q. Does Mr. Makholm further discuss Consumers Energy’s approach to developing its 5

capacity charge? 6

A. Yes. On page 18 of his testimony, Mr. Makholm states, “Consumers’ method 7

misunderstands what capacity the legislation appears to be after: the incremental facilities 8

needed to meet the projected coincident peak load as opposed to those that only provide 9

energy.” 10

Q. Do you agree with that assertion by Mr. Makholm? 11

A. No. While incremental facilities will be needed in the future to maintain reliability in 12

Michigan, Mr. Makholm’s suggestion, that those incremental facilities are the only 13

capacity resources that should be considered in the SRM capacity charge for the 14

2018-2019 planning year, ignores the role that the current fleet of resources plays in 15

maintaining reliability. Consumers Energy maintains its capacity resources so that the 16

entire fleet of owned and purchased resources, both baseload and peaking, can be used 17

holistically to meet its capacity obligations. If Consumers Energy begins providing 18

capacity to some amount of ROA load under the SRM in 2018, then Consumers Energy 19

would be using that currently existing portfolio to provide capacity on behalf of ROA 20

customers. Since those ROA customers would be receiving the benefits provided by 21

those existing resources, the existing resources should be included in the determination 22

and calculation of the SRM capacity charge. Mr. Makholm admits as much on page 16 23


rte0817-dfr 5

of his testimony, at line 12, where he includes “delays in planned retirements” as one 1

possible option for Consumers Energy to serve ROA capacity. Clearly, Consumers 2

Energy can only delay the retirement of a resource that already exists at that time. Since, 3

by Mr. Makholm’s own acknowledgement, Consumers Energy might rely on existing 4

capacity resources to serve ROA capacity, the existing resources should be included in 5

calculation of the capacity charge. 6

Q. Do you believe that your assertion that Consumers Energy’s entire fleet of capacity 7

resources is used to holistically meet capacity requirements is supported by independent 8

analysis? 9

A. Yes. In Discovery Response No. 18239-CE-ST-6, Staff witness Revere supports 10

Consumers Energy’s position that all of Consumers Energy’s owned generation provides 11

capacity service to cover Consumers Energy’s capacity requirements. In Discovery 12

Response No. 18239-CE-ST-7, Mr. Revere reaches the same conclusion for Consumers 13

Energy’s Power Purchase Agreements (“PPA”). See Exhibit A-24 (DFR-8). Mr. Revere 14

notes that those facilities provide other services beyond capacity, but the fact remains that 15

all of those facilities do provide capacity, and therefore the definition of capacity 16

resources for purposes of calculating the capacity charge should not be limited to 17

incremental resources. 18

Q. Are there other concerns with the suggestion that ROA customers should only be charged 19

for incremental capacity? 20

A. Yes. Mr. Makholm suggests in a number of places, such as page 16, line 12, of his 21

testimony, that any incremental capacity should only consist of peaking plants like 22

combustion turbines. But if ROA load is only paying for those low-cost units, bundled 23


rte0817-dfr 6

customers will continue having to pay for the capacity provided by baseload units, 1

resulting in price discrimination against those bundled customers. This would mean that 2

bundled customers would subsidize the capacity service provided to ROA customers who 3

receive capacity service from the utility. In addition, Section 6w(3) of Act 341 requires 4

that the capacity charge for ROA customers who receive capacity service from the utility 5

not differ from the capacity charge which bundled customers pay for utility capacity 6

service. Consumers Energy uses both baseload and peaking resources to provide 7

capacity to all of its capacity customers on a holistic portfolio-wide basis, so all capacity 8

customers should pay rates that are based on the same portfolio used to provide capacity. 9

Furthermore, any ROA load that becomes subject to the capacity charge and that receives 10

Consumers Energy’s capacity service will receive that service during both peak and non-11

peak times, given the annual nature of MISO’s capacity construct, so it is not reasonable 12

for ROA customers to only pay for peaking unit capacity. 13

UTILITY CAPACITY PLANNING 14

Q. Does Mr. Makholm suggest changes for how Consumers Energy must conduct its 15

capacity planning? 16

A. Yes. Mr. Makholm says, beginning on page 13, line 22, of his testimony that Consumers 17

Energy “now must add those (10% of ROA) customers into their planning process as 18

capacity-only customers, i.e. customers with potential demands but no expected loads on 19

the system.” 20

Q. Do you agree with Mr. Makholm’s assertion? 21

A. No. Mr. Makholm seems to believe that Consumers Energy must plan as though all ROA 22

load is going to become subject to the SRM capacity charge, and therefore take 23


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Consumers Energy’s capacity service, indefinitely. Presumably, that would require 1

Consumers Energy to actually procure some kind of capacity resources to meet that load, 2

something that would need to be planned for years in advance. Essentially, 3

Mr. Makholm’s suggestion would require Consumers Energy to have capacity to meet 4

100% of all load in its distribution service territory, even though Consumers Energy 5

would not know what, if any, ROA load would actually become served by utility capacity 6

and therefore become subject to the capacity charge, or when they would start receiving 7

utility capacity service and become subject to the SRM capacity charge – meaning that 8

Consumers Energy would have to maintain additional capacity resources even if it was 9

not clear that those resources would be paid for by the ROA load they were meant to 10

serve. If it turned out that no ROA load, or only a small amount of ROA load, needed to 11

be served by Consumers Energy’s capacity, then Consumers Energy would have 12

developed additional capacity only to find that the intended customer loads were not 13

there to be served by it or pay for it. The end result would be additional costs for bundled 14

customers, who would be paying for additional capacity that is in fact not needed. The 15

Commission should reject Mr. Makholm’s suggestion to require the utility to be long on 16

capacity based on the possibility that ROA load may become capacity load of the 17

Company if its AES fails to meet resource adequacy requirements. This would require 18

the Company’s customers to subsidize ROA load, which would be unreasonable and 19

unfair. 20


rte0817-dfr 8

Q. What impact would an obligation to be long on capacity, in order to potentially serve 1

ROA load whose AESs fail to demonstrate sufficient capacity, have on Consumers 2

Energy? 3

A. This approach would expose Consumers Energy to undue risk that is not contemplated by 4

Act 341. The legislation intends to determine an appropriate level of capacity that is 5

needed in Michigan, and to ensure that some party secures that capacity and that the 6

customers who benefit from that capacity pay for it. The legislation is not intended to 7

require utilities to plan to serve potentially more customers than they will actually have, 8

which would result if utilities plan to serve 100% of the load in their distribution 9

territories with capacity while AESs might also be planning to serve up to 10% of that 10

same load. The legislation is not intended to require utilities and their bundled customers 11

to be exposed to the capacity costs associated with unnecessary overbuilding. Further, if 12

utilities are required to plan to serve ROA customers with capacity service, the 13

oversupply that would result will depress spot market prices at the time utilities in other 14

jurisdictions will be balancing their capacity needs thus causing the benefits of the 15

oversupply to be given to others without just compensation for the Company’s full 16

service customers. 17

MARGINAL COST-BASED RATEMAKING 18

Q. What distinction does Mr. Makholm draw between marginal-cost-based ratemaking and 19

embedded-cost-based ratemaking? 20

A. On pages 21 and 22 of his testimony, Mr. Makholm discusses the differences between the 21

two approaches, indicates his preference for marginal-cost-based ratemaking, and 22

acknowledges that Michigan is an embedded-cost-based state. He then suggests that 23


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Consumers Energy should have calculated its capacity charge on a forward-looking basis, 1

considering only the marginal cost of serving ROA load with capacity – again claiming 2

that the capacity charge should be based only on incremental capacity rather than 3

Consumers Energy’s entire integrated portfolio. He criticizes Consumers Energy’s 4

capacity charge as “simply a figure by which AES suppliers would be charged a pro rata 5

share of Consumers Energy’s historical revenue requirement net of what it lists as non-6

capacity-related expenses.” 7

Q. Is Mr. Makholm’s criticism consistent with Section 6w of Act 341? 8

A. No. As Mr. Makholm acknowledges, Michigan’s well-established ratemaking polices 9

provide for the recovery of embedded costs as well as approved forecasted costs, even if 10

Mr. Makholm believes that marginal-cost-based approaches are more economically 11

efficient. Embedded costs ratemaking considers historically-based costs, considering 12

assets that are already in place, as well as forecasted costs. This approach of included 13

embedded costs in rates was clearly maintained in Act 341. Section 6w(3)(a), in 14

describing how the capacity charge should be calculated, directed the utility to, “include 15

the capacity-related generation costs included in the utility’s base rates, surcharges, and 16

power supply cost recovery factors, regardless of whether those costs result from utility 17

ownership of the capacity resources of the purchase or lease of the capacity resource from 18

a third party.” There is nothing in that statutory language that suggests that Consumers 19

Energy’s calculations should be “forward-looking, planning-based, or market-based” as 20

Mr. Makholm wishes for on page 23, line 15, of his testimony. The statutory language is 21

clear that the capacity charge should be ultimately based on the utility’s approved 22

revenue requirement, which in Michigan includes historical as well as forecasted costs. 23


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Michigan is not a marginal-cost ratemaking state, and Section 6w(3) instruction to 1

include in the SRM capacity charge capacity-related costs included in base rates, 2

surcharges, and power supply cost factors recognizes this fact. 3

SRM CAPACITY CHARGE ASSESSED TO AESs 4

Q. Are there any other concerns with Mr. Makholm’s description of Consumers Energy’s 5

capacity charge? 6

A. Yes. He describes the charge as applying to “AES suppliers.” The charge does not apply 7

to AESs; it applies directly to ROA customers. AESs do not pay the utility for capacity. 8

The Commission has previously indicated that the SRM capacity charge would be a retail 9

rate charged to ROA customers. 10

CONE AS A PROXY, OR CAP, FOR THE SRM CAPACITY CHARGE 11

Q. What implications does this have for Mr. Makholm’s assertion that CONE, as developed 12

by MISO, should be used as a cap on the SRM capacity charge? 13

A. Mr. Makholm’s suggestion, appearing on page 30, lines 13 through 16 of his direct 14

testimony, is not provided for in Act 341. The language of Act 341, Section 6w(3)(a) 15

clearly intends for the utility to rely on its own base rates, surcharges, and Power Supply 16

Cost Recovery (“PSCR”) costs to determine the capacity charge. Act 341 does not 17

provide for the charge to be based on an external calculation like CONE. The language 18

of Act 341 does not assume that the capacity charge must be market-based, being instead 19

based on the utility’s costs included in its rates. 20


rte0817-dfr 11

Q. Does that also apply to the suggestion made by Mr. Revere and Mr. Dauphinais that 1

CONE could or should be used to determine the cost of capacity to be included in the 2

Company’s SRM capacity charge? 3

A. Yes. On page 5 of his testimony, Mr. Revere makes the argument that CONE is the 4

proper cost of capacity for this case, claiming that a combustion turbine designed for the 5

primary purpose of meeting peak demand is the only kind of unit that should be 6

considered in cost of capacity for purposes of the SRM capacity charge. Similarly, 7

Mr. Dauphinais suggests, on page 23 of his testimony, that CONE should be used as 8

some kind of benchmark in setting the SRM capacity charge. Again, this is not 9

consistent with the way in which Consumers Energy uses its entire capacity portfolio to 10

meet its entire load in a holistic manner, as Mr. Revere acknowledges in Discovery 11

Response Nos. 18239-CE-ST-6 and 18239-CE-ST-7. See Exhibit A-24 (DFR-8). These 12

claims do not reflect the fact that, since MISO’s capacity requirements are set on an 13

annual basis and apply throughout the year, all capacity addressing the Planning Reserve 14

Margin Requirement (“PRMR”) needs to be available to MISO throughout the year. 15

Because of MISO’s annual capacity construct, both ROA load and bundled load need to 16

be served with their full capacity requirement every hour of the year, which relies on the 17

utility’s entire capacity portfolio. 18

Q. Are there other concerns about reliance on CONE to determine the capacity charge? 19

A. Yes. While CONE is used by MISO to determine a price cap and other parameters for 20

the Planning Reserve Auction (“PRA”), that does not make it a suitable proxy for the cost 21

of capacity to be included in the SRM capacity charge. In order to achieve the express 22

purpose of an SRM (“to ensure reliability of the electric grid in this state” (see MCL 23


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460.6w(12(h)), the Commission should provide incentives to ensure that needed capacity 1

is actually developed in Michigan. Even if the PRA were to clear at CONE, this would 2

not be a high enough capacity price to actually incent the building of new capacity by 3

merchant generators, even a simple-cycle gas combustion turbine. This premise was 4

addressed by Mr. Makovich in testimony to the Michigan Senate Energy and Technology 5

Committee in its consideration of energy policy legislation which ultimately led to the 6

enactment of Act 341. See page 7 in Exhibit A-21 (DFR-5). 7

Q. Do the arguments against using CONE to determine the capacity charge also apply to 8

Mr. Makholm’s suggestion, on pages 30 and 31 of his testimony, to base the capacity 9

charge on the results of Consumers Energy’s 2017 reverse capacity auction? 10

A. Yes, Mr. Makholm is incorrect regarding the reverse capacity auction’s applicability to 11

this case. As I have previously stated, Section 6w(3)(a) of Act 341 directs Consumers to 12

calculate its capacity charge based on “the capacity-related generation costs included in 13

the utility’s base rates, surcharges, and power supply cost recovery factors, regardless of 14

whether those costs result from utility ownership of the capacity resources of the 15

purchase or lease of the capacity resource from a third party.” The results of the reverse 16

capacity auction indicate the price of a small portion of the resources in Consumers 17

Energy’s current capacity portfolio. Mr. Makholm is simply trying, by alluding to the 18

reverse capacity auction, to claim once again that the capacity charge should be set based 19

on some forward-looking market basis when this is not what the statute requires. 20


rte0817-dfr 13

THE 30-YEAR TERM FOR THE SRM CAPACITY CHARGE 1

Q. What is Mr. Makholm’s position on Consumers Energy’s proposed 30-year capacity 2

charge term? 3

A. Mr. Makholm is opposed to Consumers Energy’s proposal, and dismisses Consumers 4

Energy’s concerns about gaming the system by asserting that Consumers Energy would 5

not likely build new capacity to serve ROA load, and could instead rely on market 6

purchases. 7

Q. Could Consumers Energy simply rely on short-term market purchases, as Mr. Makholm 8

suggests? 9

A. It is not reasonable to assume that capacity will be available to purchase in a low price 10

capacity market indefinitely. Consumers Energy contemplates making additional market 11

purchases through the PRA in 2018 as a means to serve ROA load, as that might be the 12

only means to acquire any capacity given the short timeframe that will be available after 13

AESs make their resource adequacy filings in February 2018. That does not mean 14

Consumers Energy would do that every year, nor does it mean that it would be possible 15

to do so. In June 2017, MISO released its most recent MISO-Organization of Midwest 16

States (“OMS”) Survey on resource adequacy. That survey projects that, in 2022, Local 17

Resource Zone (“LRZ”) 7 covering Michigan’s Lower Peninsula will face a capacity 18

shortage of between 1.1 GW and 1.5 GW. See Exhibit A-23 (DFR-7), which is a copy of 19

the 2017 MISO-OMS Survey Results. Given those numbers projected by MISO, LRZ 7 20

might not have enough capacity within the LRZ to meet its LCR, meaning there might 21

not be enough capacity and transmission transfer capability available to buy in 2022 to 22

maintain adequate local reliability. In order to ensure that the LCR is achieved in LRZ 7, 23


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some party is going to need to invest in new capacity in the Lower Peninsula of 1

Michigan. This was further reinforced with the Commission’s July 31, 2017 Order, in 2

Case No. U-18197 (“July 31 Order”), which found that there is a “tightening of capacity 3

supplies in Michigan,” and that, while LRZ 7 will have adequate supply in the summer of 4

2018 once imports are counted, it is still “highly likely that Michigan will need additional 5

capacity resources within the state, due to expected retirements, to meet the LCR in the 6

coming years.”1 7

Q. Does Mr. Makholm consider which party will make the needed investment in new 8

capacity? 9

A. Mr. Makholm makes the general argument, for example on page 34 of his testimony, that 10

unregulated merchant generators can be relied on to develop any needed new capacity 11

going forward. 12

Q. Is that a reasonable assumption? 13

A. It is not clear that it is a reasonable assumption in LRZ 7. No merchant operators have 14

built new generators in LRZ 7 in several years, as the capacity prices in the MISO PRA 15

have been very low. In Discovery Response No. 18239-CE-AB-4, ABATE is not able to 16

cite any merchant generation that has been built in Michigan since 2004. See Exhibit A-17

22 (DFR-6). That fact points largely to the way that the PRA is designed; those PRA 18

prices are only on a year-by-year term, so they do not reflect either the availability of 19

capacity or its price in a forward year like 2022, when there is a potential local shortage. 20

Furthermore, existing merchant generation in LRZ 7 has been leaving. For example, the 21

New Covert gas-fueled plant – the most recent merchant generator built in Michigan, 22

1 July 31, 2017 Order in MPSC Case No. U-18197, page 8


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according to ABATE’s list in Discovery Response No. 18239-CE-AB-4, was originally 1

interconnected to the MISO system but recently paid to build transmission to connect to 2

PJM Interconnection, LLC. In short, assuming that merchant generators will show up in 3

the nick of time to build needed resources before there is a shortage is risky, because the 4

MISO PRA is not designed to send price signals on a forward basis that could incent that 5

generation. 6

Q. If it is unlikely that merchant generators will build new capacity in Michigan, are any 7

other parties likely to build? 8

A. Yes, other plans exist. For example, DTE Electric Company (“DTE”) applied for a 9

Certificate of Necessity from the Commission on July 31, 2017, coincidentally the same 10

day that the Commission found that new capacity would soon be needed in Michigan.2 11

DTE proposed to build a 1,100-MW gas plant that would be in service by 2022, just as 12

that need becomes manifest. Consumers Energy has not been idle in developing new 13

capacity either, by, for example, expanding the capacity of the Cross Winds® Energy 14

Park to address incremental needs; overhauling and upgrading the Ludington Pumped 15

Storage facility to add approximately 55 MW of capacity for each upgraded generator; 16

negotiating a change in a PPA that adds approximately 150 MW of capacity in the 2019- 17

2021 period; and developing demand response programs that offset the need for capacity. 18

In short, the suggestion that utilities may simply buy market capacity into the indefinite 19

future to address any ROA load is short-sighted, risky, and inaccurate. 20

2 MPSC Case No. U-18419.


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Q. Are there other arguments that parties have made regarding the length of the capacity 1

charge term in this case? 2

A. Mr. Stocking, on page 5, line 15, of his testimony, argues that Consumers Energy’s 3

proposed 30-year capacity charge term “conflicts with Act 341 because the statute states 4

that a charge shall not be assessed when an AES can demonstrate that it meets its 5

capacity obligations?” 6

Q. Do you believe Mr. Stocking’s interpretation of the statute is correct? 7

A. No. The section of Act 341 referenced by Mr. Stocking (MCL 460.6w(6)) provides, in 8

relevant part, that “a capacity charge shall not be assessed for any portion of capacity 9

obligations for each planning year for which an alternative electric supplier can 10

demonstrate that it can meet is capacity obligations through owned or contractual rights 11

to any resource that the appropriate independent system operator allows to meet the 12

capacity obligation of the electric provider.” This section simply means that if an AES 13

meets resource adequacy requirements, the SRM capacity charge will not apply to the 14

AES’s load. It does not limit the Commission’s discretion to determine the term of the 15

SRM capacity charge to apply once an AES fails to demonstrate resource adequacy. As 16

previously recognized by the Commission in its orders initiating this proceeding, the term 17

of the applicable SRM capacity charge is to be determined by the Commission. 18

Consumers Energy submits that Section 6w(8)(b)(i) of Act 341 demonstrates the 19

Legislature’s intent for the SRM capacity charge to apply for a minimum of four years if 20

an AES does not demonstrate sufficient resource adequacy in a four-year forward 21

capacity demonstration. The Company believes that the Commission has discretion 22

under Section 6w to determine a period that the SRM capacity charge is effective (i.e., a 23


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term of longer than four years) in order to comply with the defined purpose of an SRM—1

to ensure the reliability of the electric grid in this state. 2

My direct testimony in this case presented Consumers Energy’s rationale for why 3

a 30-year capacity charge term is necessary, to ensure that Consumers Energy’s costs to 4

procure additional capacity can be recovered from the appropriate set of customers. At 5

such time that an AES is unable to demonstrate that it has sufficient capacity to satisfy its 6

obligation on a forward basis the SRM capacity charge is assessed for the forward period 7

established by the Commission and the obligation to provide capacity for the affected 8

customers shifts to the regulated utility for the balance of the term of the charge. The 9

statute provision referred to by Mr. Stocking is not in conflict with this approach because 10

during any period during the term the SRM charge is effective the obligation to serve 11

ROA customers subject to the SRM capacity charge rests not with the AES but with the 12

regulated utility. The cited portion of the statute applies with respect to load for which 13

the AES retains the obligation to provide capacity. The intent of Section 6w of Act 341 14

is to ensure that there is sufficient capacity in Michigan, and that the customers who 15

benefit from given capacity are the ones who pay for it. If the capacity charge is not set 16

for a sufficient length, then it is entirely possible to have situations in which some 17

customers are not paying for capacity that was developed to benefit them. Although 18

some options for procuring incremental capacity to serve ROA customers may be 19

exercised on an annual basis, other options would not be, including both new generation 20

builds and long-term power purchase agreements. For instance a utility may not be able 21

to justify the construction of new capacity and Independent Power Producers may be 22

unwilling to supply a market that is based on a single year of revenue at CONE derived 23


rte0817-dfr 18

on an assumption of revenue requirements being recovered over 30 years or more. If 1

ROA customers come and go from taking utility capacity on an annual basis, then it 2

would be possible for those customers to take utility capacity, obligate the utility to 3

procure incremental capacity, and then leave utility capacity service, leaving the utility its 4

remaining customers with what has become unnecessary capacity. This would run 5

counter to the intent of the legislation, would make utility capacity planning more 6

difficult than prior to the enactment of Act 341, due to increased uncertainty, and would 7

result in bundled customers being forced inequitably to pay for capacity that is explicitly 8

meant to benefit ROA customers. 9

THE ROA 10% CAP 10

Q. Staff witness Cantin asserted that ROA customers who become subject to the capacity 11

charge and later return to bundled service should create new space under the 10% cap. 12

Do you agree with her position? 13

A. No. Consumers Energy has proposed that if an ROA customer becomes subject to the 14

capacity charge, and later on decides to return to bundled service, that should not create 15

new space under the 10% cap during the term that the SRM capacity charge would 16

otherwise apply. If an ROA customer is subject to the SRM capacity charge, then that 17

would indicate that the customer’s AES does not have sufficient capacity to serve its 18

customers. If the ROA customer chose to return to full bundled service, the AES would 19

still not have enough capacity to serve a new customer that might otherwise move out of 20

the queue to take the place of a customer being assessed the SRM capacity charge 21

electing to switch from ROA service to bundled service. This revolving door would 22

similarly create uncertainty around Consumers Energy’s planning process, and make it 23


rte0817-dfr 19

difficult to ensure that a given customer was paying for the capacity from which it was 1

receiving a benefit. Ms. Cantin suggests on page 8, line 16, of her testimony that if this 2

revolving door results in the utility being long in capacity, then it can “evaluate whether 3

to retain the extra capacity, sell some extra capacity, or investigate retiring facilities that 4

may no longer be needed as part of its normal resource planning activities.” This is not a 5

workable solution, and is unfair to the Company’s bundled customers. If the capacity 6

charge term is limited to a single year, then the utility could only sell extra capacity on an 7

annual basis without exposing itself to the risk that it would again need that capacity in 8

future years. This problem would be even more pronounced in the case of examining a 9

retirement of a generating unit; if ROA load can come and go from utility capacity 10

service on an annual basis, then retiring capacity would be particularly risky. In general, 11

“normal resource planning activities” require assumptions based on projections many 12

years into the future; it does not work if up to 10% of load may come and go every year. 13

Further, MISO rules require surplus capacity to be offered into the PRA, thus potentially 14

making this surplus capacity, paid for by bundled customers, available to AES at sharply 15

discounted prices. 16

MARKET ENERGY SALES 17

Q. Do you agree with Mr. Revere’s position on deducting intersystem sales from the 18

calculation of capacity costs? 19

A. No. Section 6w(3)(b) requires energy market sales to be deducted from the calculation of 20

capacity costs. This requirement makes sense when the SRM capacity charge is 21

calculated and assessed on an annual basis, but Consumers Energy was a net buyer of 22

energy from the MISO Market in over 99% of the hours in 2014, 2015, and 2016 and on 23


rte0817-dfr 20

an annual basis in each of those years. Even if Consumers Energy did deduct the de 1

minimis amount of market sales in those few hours in which it was a net seller, there 2

would be nothing to deduct the vast majority of the time, unless Consumers Energy were 3

to “deduct” a negative number to reflect its position as a net buyer. It would also not be 4

appropriate to claim that Consumers Energy should deduct everything that was paid to its 5

generators in those hours that it was a net buyer, when it paid an even greater amount to 6

MISO than it received. Interpreting that revenue during those hours as a “sale” would not 7

be an accurate understanding of MISO’s settlement system. Consumers Energy is, during 8

those hours, effectively selling energy to itself, clearing it through MISO’s settlement 9

system, plus buying additional energy to meet its needs. Mr. Jennings’ testimony and 10

exhibits are inaccurate in a similar manner – Mr. Jennings has calculated the entire output 11

of Consumers Energy’s owned generation and PPAs and multiplied that by a forecasted 12

price, and concluded that that entire figure represents Consumers Energy’s energy market 13

sales. Again, this is not an accurate reflection of how the MISO energy market works. 14

Consumers Energy is only actually selling energy to the market in those hours that it is a 15

net seller. Additionally, even if Mr. Jennings interpretation of market energy sales was 16

correct, he did not deduct the incremental cost to generate the energy sales, and thus 17

overstates the net revenue from these sales. While it appears that the cost of fuel used at 18

the Company’s owned plants was deducted from the market sales revenues, the energy 19

costs (as a proxy for fuel costs) associated with PPAs is not discussed in Mr. Jennings’ or 20

Mr. Smith’s testimony. Unfortunately, Mr. Jennings does not provide sufficient detail in 21

his testimony or exhibits about how he used the Aurora dispatch model to estimate what 22

he believes would be energy market sales, nor has he made such provision in any 23


rte0817-dfr 21

discovery response, so Consumers Energy is not able to determine the scale of this 1

overstatement, nor to more generally evaluate Mr. Jennings’ modeling approach. 2

Q. Does a similar logic apply to Mr. Jennings’ conclusions about ancillary service sales? 3

A. Yes. Just like with the energy market, while Consumers Energy does receive some 4

revenue for providing ancillary services in MISO, Consumers Energy pays even more on 5

a net basis and is therefore a net buyer. The same logic applies as discussed above with 6

the energy market – Consumers Energy is effectively selling to itself, cleared through the 7

MISO settlements process, and is buying more on top of that. 8

Q. What is the consequence of Mr. Jennings’ inaccurate methodology? 9

A. By incorrectly including the aforementioned energy market and ancillary service market 10

revenue as though it were “sales,” Mr. Jennings would deduct about $1 billion annually 11

from the costs that Consumers Energy has used to calculate its capacity charge. This is 12

unreasonable, does not reflect reality, and should be rejected. 13

PRORATION OF THE SRM CAPACITY CHARGE TO ROA CUSTOMERS 14

Q. Is Mr. Stocking accurate when he asserts that Consumers Energy should be able to 15

prorate the capacity charge among multiple customers? 16

A. No. Mr. Stocking is making an apples-to-oranges comparison. On page 8, line 10, of his 17

testimony, he argues that “resource planning is typically done on an aggregate basis… the 18

practice of assigning a particular capacity resource to a particular customer, yet charging 19

a uniform capacity price to all customers, does not seem equitable.” Mr. Stocking is 20

correct in that Consumers Energy does indeed use its entire capacity portfolio to serve its 21

total capacity obligations, as I have already discussed. Consumers Energy proposes to 22

assign the capacity charge, calculated based on its entire portfolio, to customers on a 23


rte0817-dfr 22

simple in-or-out basis. Mr. Revere also takes up this argument, saying on page 14, line 1

15 of his testimony that Consumers Energy prorates charges on a regular basis. But 2

Mr. Revere’s counterexamples are based more on situations in which Consumers Energy 3

must make billing adjustments following rate case orders, not situations in which 4

Consumers Energy takes a given charge and splits it among a series of customers. 5

2018 SRM CAPACITY CHARGE UPDATE 6

Q. Do you agree with Mr. Dauphinais’ suggestion that Consumers Energy be required to file 7

an updated capacity charge following AESs’ capacity demonstrations in February 2018? 8

A. No. Mr. Dauphinais laments, in the first instance on page 4, line 19, that Consumers 9

Energy calculates its capacity charge assuming that no ROA customers will actually take 10

utility capacity service. But, given the timeline that was provided for by the Legislature, 11

and given that the Commission decided to keep the AES capacity demonstration deadline 12

in February rather than setting it for an earlier date, Consumers Energy has no basis by 13

which to make any other assumption, which Mr. Dauphinais admits in Discovery 14

Response No. 18239-CE-AB-5. See Exhibit A-22 (DFR-6). I have already explained 15

why it would be unreasonable to assume that all ROA load would take utility capacity 16

when discussing Mr. Makholm’s testimony. Neither Mr. Dauphinais nor any other 17

witness proposes an alternative percentage between zero and 10% that Consumers 18

Energy should assume will take utility capacity. 19


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DURATION OF THE SRM 1

Q. Do you agree with Mr. Dauphinais’ suggestion that the SRM should not be implemented 2

perpetually, and should instead be reviewed by the Commission on an annual basis after 3

the initial four-year period required by Act 341? 4

A. No. I have already addressed the need for some long-term certainty in my discussion of 5

Consumers Energy’s proposed 30-year capacity charge term. Beyond the capacity charge 6

term, perpetual implementation of the SRM itself is necessary to ensure that the 7

Commission is given an annual opportunity to review the capacity plans of all electric 8

providers in Michigan. As noted by Staff witness Stocking, on page 4, line 1 of his 9

testimony, the “SRM provides the Commission with a tool to ensure the long-term 10

reliability of the electric grid in Michigan.” Consumers Energy further notes that, if the 11

Commission were to stop implementation of the SRM at some point, i.e. because the 12

Commission determined that it was no longer necessary to ensure reliability, then Act 13

341 does not contain any provision or mechanism to “restart” the SRM if an apparent 14

reliability issue reemerges. It would not make sense for the Commission to go through an 15

annual review process through which it might lock itself out of using the SRM to ensure 16

reliability in the future so long as utility service is provided in the form the Company’s 17

customers currently enjoy. 18

CAPACITY RELATED GENERATION COST 19

Q. Do you agree that the MISO PRA is voluntary, as Mr. Dauphinais describes on page 7, 20

line 6, of his testimony? 21

A. This is technically true in a narrow sense, but it misses the point of how MISO’s capacity 22

construct works. The PRA is voluntary, in that load in MISO may use a Fixed Resource 23


rte0817-dfr 24

Adequacy Plan (“FRAP”) to meet its capacity obligations outside of the PRA itself, 1

without having to participate in the auction. MISO loads also have the option of paying a 2

Capacity Deficiency Charge, but the charge is set so high that it is assumed that no one 3

would ever actually choose this option, and to date no one has. In short, while the PRA 4

itself is voluntary, participation in the MISO capacity construct in general is effectively 5

mandatory unless the load is willing to pay significant financial penalties. In any case, 6

those financial penalties do not actually cause the development of any new capacity 7

resources or do anything else to enhance resource adequacy. 8

Q. What are the “Federal Reliability Requirements” described in Section 6w of Act 341? 9

A. As Mr. Dauphinais notes in his testimony on page 12, line 13, Act 341 does not provide a 10

definition. However, Mr. Dauphinais goes on to speculate that the federal reliability 11

requirements simply refer to MISO’s LCR and PRMR. Consumers Energy agrees that 12

these items are part of federal reliability requirements. It is also important to 13

acknowledge that federal reliability requirements include a 1-day-in-10 years Loss of 14

Load Expectation (“LOLE”). That standard is used by MISO when developing LCR and 15

PRMR. When considering how to ensure that federal reliability requirements are met 16

under Act 341, it is important that the end result ensures that the 1-day-in-10-years LOLE 17

standard continues to be maintained to ensure reliability. 18

Q. Do you agree with Mr. Dauphinais’ conclusions about what should constitute “capacity-19

related generation costs” under Section 6w of Act 341? 20

A. No. On page 14 of his testimony, Mr. Dauphinais says that the capacity charge should 21

exclude all utility generation costs that are not involved in providing MISO Zonal 22

Resource Credits (“ZRCs”), based on his interpretation that ZRCs are what MISO uses to 23


rte0817-dfr 25

ensure that federal reliability requirements are met. But, as I have already stated, 1

Consumers Energy uses its entire portfolio of capacity resources to ensure that a 1-day-2

in-10-years LOLE standard is met in a holistic manner, so the entire portfolio is engaged 3

in meeting federal reliability requirements. Further, as I have already stated, Section 4

6w(3) of Act 341 provides that the capacity charge must “include the capacity-related 5


recovery factors, regardless of whether those costs result from utility ownership of the 7

capacity resources of the purchase or lease of the capacity resource from a third party.” 8

Consumers Energy followed this instruction in developing its capacity charge in this 9

case. 10

ELECTIONS TO INCUR THE SRM CAPACITY CHARGE 11

Q. Is Mr. Dauphinais correct, beginning on page 35, line 23, of his testimony, when he says 12

that “some ROA customers may want to contract for capacity with the AES and others 13

may just elect to pay the SRM Capacity Charge?” 14

A. No. Nothing in Section 6w of Act 341 allows for such a choice to be made by an ROA 15

customer. Section 6w was not intended to turn capacity into an “a la carte” capacity 16

product. On the contrary, Section 6w(8)(b)(i) provides that when an AES does not have 17

sufficient capacity to meet its load obligations, then the Commission must “require the 18

payment of a capacity charge” for the relevant ROA load. The ROA customer does not 19

have the choice to pursue some other route, except to return to bundled utility service. 20

Further, there is no provision in the statue that gives an ROA customer the option to pay 21

the capacity charge in the event that its AES actually does have sufficient capacity. It 22

would appear, based on ABATE’s response to Discovery Request No. 18239-CE-AB-11, 23


rte0817-dfr 26

that the intention of its implied “a la carte” concept would be to allow ROA load to flip 1

back and forth between receiving capacity from the AES and paying the capacity charge 2

to receive utility capacity on an annual basis. See Exhibit A-25 (DFR-9). ABATE’s 3

suggestion envisions a construct in which an AES could decide to provide capacity to its 4

customers one year; then, based on terms inserted into its contracts with its customers, 5

push them onto utility capacity for a year; and finally, resume providing capacity to its 6

customers the following year. Representatives of CNE represented this as part of their 7

future plans during the technical conference in Case No. U-18197 on June 29, 2017. This 8

is the exact sort of gaming that Consumers Energy cites when arguing that a 30-year 9

capacity charge term is necessary. 10

AES BILLING OF SRM CAPACITY CHARGES 11

Q. How does Mr. Campbell propose that the capacity charge get billed? 12

A. On page 5, line 8, of his testimony, Mr. Campbell recommends that AESs “continue to 13

manage capacity costs for all of their customers by billing the SRM capacity charge to 14

the AES,” who would then bill their customers. 15

Q. Is this an acceptable approach? 16

A. No. As I previously noted, AESs are not permitted to pay the utility for capacity under 17

the provisions of Act 341 and the Commission’s previous determination that the SRM 18

capacity charge will be a retail charge applied to retail customers, and not to AESs. 19


rte0817-dfr 27

EXPLANATIONS OF MISO CAPACITY RULES 1

Q. Is Energy Michigan witness Zakem correct in his assertion on pages 6 and 7 of his 2

testimony that it is wrong for MISO Load Serving Entities (“LSEs”) to say, “Our 3

resources serve our load?” 4

A. It is a misleading statement at best. It is true that MISO is able to pool capacity resources 5

together to enhance reliability and to provide more robust planning reserve margins, and 6

it is true that electrons may flow on the grid in such a way that they may originate at a 7

generation resource owned by one company and end up at a load served by another 8

company. But Mr. Zakem’s assertion ignores the fact that a large majority of LSEs in 9

MISO are regulated utilities with an obligation to serve their native load, and that those 10

LSEs plan to develop their own capacity resources, in conjunction with their state 11

regulators, to serve their own load. This is most obvious in cases where LSEs use a 12

FRAP, under which an LSE specifies a certain set of capacity resources to MISO that that 13

LSE will use to meet its own capacity obligations. The existence of the FRAP in MISO’s 14

Tariff is a clear recognition by MISO that many LSEs do use their own resources to serve 15

their own load, again notwithstanding the actual physical flow of electrons. 16

Q. Is Mr. Zakem correct in his assertion on page 11 of his testimony that “even if and when 17

an LSE owns a ZRC, the LSE satisfies its MISO obligations with money – paying the 18

Auction Clearing Price (‘ACP’) – not with ownership of that ZRC?” 19

A. Only partially. Mr. Zakem’s description of the PRA process, on pages 10 and 11 of his 20

testimony, is more or less accurate. But that is only relevant in cases in which an LSE is 21

actually paying the Auction Clearing Price (“ACP”) in the manner that Mr. Zakem is 22

illustrating. On page 10, line 15, of his testimony, Mr. Zakem alludes to “one exception” 23


rte0817-dfr 28

to this process. Only later, on page 15, line 2, does Mr. Zakem state that the one 1

exception is the FRAP itself. The way that Mr. Zakem’s testimony is written might 2

suggest that most MISO LSEs are simply paying the ACP in a process in which MISO 3

“buys all and sells all,” with the FRAP being an obscure footnote in MISO’s Tariff. On 4

the contrary, the FRAP is a key component of MISO’s resource adequacy construct, 5

which, as I already stated, is used by MISO to recognize that many LSEs use their own 6

resources to serve their own load in a traditional, state-regulated manner. Mr. Zakem 7

seems to imply on page 15, line 6, of his testimony that the FRAP is limited to a small 8

number of municipalities, but it is in fact used by investor-owned utilities as well, 9

including Consumers Energy. In addition, Mr. Zakem’s essential dismissal of the MISO 10

FRAP process ignores the fact that the Section 6w resource adequacy demonstrations, 11

which form a condition precedent for the application of the SRM capacity charge at issue 12

in this proceeding, are analogous to a MISO FRAP process, in that electric providers in 13

Michigan are required, pursuant to Section 6w, to demonstrate owned or purchased 14

capacity resources for their retail loads in Michigan. 15

Q. Are there options for LSEs besides the FRAP and simply paying the ACP in the PRA? 16

A. There is a third option. LSEs that own capacity resources can “self-schedule” those 17

resources into the PRA, effectively offering them into the PRA at a price of zero with the 18

expectation that they will receive the PRA clearing price. While this process, unlike the 19

FRAP, is administered as part of the PRA, it is functionally much more similar to the 20

FRAP to the extent that resources do not exceed load – an LSE is still declaring to MISO 21

that it will in fact use its own resources to serve its own load. 22


rte0817-dfr 29

Q. Is Mr. Zakem correct in his claim on page 14 of his testimony that Consumers Energy 1

cannot actually “provide capacity to meet the capacity obligation of the portion of an 2

AES load that is covered by an SRM charge?” 3

A. No, he is not. Section 6w of Act 341 clearly allows a utility to do this, and in fact 4

requires the utility to do this. Mr. Zakem suggests that the only way for this to work is 5

for there to be a wholesale transaction between the utility and the AES, and he alludes to 6

“legal issues” with this. However, Act 341 clearly establishes the SRM capacity charge 7

as a retail transaction that takes place directly between the utility and the ROA customer. 8

As a retail transaction, it is my understanding that it falls within the state’s jurisdiction. 9

Mr. Zakem also believes that the utility cannot “reassign a forecast PRMR from one LSE 10

to another, nor can MISO reassign a PRMR obligation from one LSE to another.” 11

Mr. Zakem believes that, because of this, an ROA customer that pays the capacity charge 12

may end up being double-billed for capacity. But Mr. Zakem’s original premise is 13

incorrect. MISO’s Peak Load Contribution (“PLC”) process is regularly used to shift 14

capacity obligations among different LSEs. If the SRM process shifts some capacity 15

obligation from an AES to the utility, the PLC process can be used to reflect that shift at 16

MISO and prevent double-billing for capacity. 17

Q. Would this also affect the claims made by Mr. Zakem on page 19, lines 9 through 13, of 18

his testimony? 19

A. Yes. Mr. Zakem attempts to lay out several so-called “boundary conditions” that he uses 20

to underpin the wide-ranging alternative proposal to Act 341 that he makes in this case. 21

Two of those boundary conditions are: 22


rte0817-dfr 30

• “Under the MISO tariff, an AES still has to pay MISO to 1 satisfy its PRMR, even if Consumers Energy claims to take 2 responsibility.” 3

• “Under the MISO tariff, Consumers Energy as a Local 4 Distribution Company (“LDC”) in MISO cannot reassign 5 forecast load or PRMR from one LSE to another, including 6 from an AES to Consumers Energy.” 7

As I have already stated, Mr. Zakem is not accurately representing MISO’s Tariff, not the 8

least because MISO has no such term as “Local Distribution Company.” (Mr. Zakem 9

appears to be referring to Consumers Energy’s role as an Electric Distribution Company 10

(“EDC”).) As an EDC, Consumers Energy participates in the PLC process to shift 11

capacity obligations among the LSEs on Consumers Energy’s distribution system as 12

customers shift between suppliers. 13

Q. Is Mr. Zakem correct in his assertion on page 17, line 20, of his testimony that Section 14

6w of Act 341 is in conflict with the MISO Tariff? 15

A. No. As I have already discussed, Mr. Zakem’s overall claim is based on the idea that 16

LSEs do not actually meet their capacity obligations with ownership of physical 17

resources, and he claims that capacity obligations in MISO are solely met with financial 18

transactions. Mr. Zakem’s premise is not an accurate representation of MISO’s entire 19

resource adequacy construct, given the existence, in particular, of the FRAP. 20

Q. Beyond the two “boundary conditions” addressed already, what is your assessment of the 21

other “boundary conditions” proposed by Mr. Zakem? 22

A. Two of the other conditions, stating (1) that MCL 460.11(1) applies to rates set by the 23

Commission, and (2) that Consumers Energy currently would need to procure additional 24

capacity if it takes on additional capacity under the SRM, are accurate. The one 25

remaining condition, that “a retail customer is not a MISO market participant or a MISO 26


rte0817-dfr 31

LSE,” is also accurate, but it is not relevant. In discussing this purported condition on 1

page 20, line 17, of his testimony, Mr. Zakem says that “a retail customer cannot be 2

charged for any service under the MISO wholesale tariff.” As I have already discussed, 3

retail customers are not charged for any wholesale products under Section 6w of Act 341. 4

Even if MISO’s Tariff deals with resource adequacy issues, resource adequacy is 5

ultimately under state jurisdiction. The provisions of Section 6w of Act 341 involve 6

retail customers paying a retail charge to the utility. 7

Q. What is your conclusion regarding Mr. Zakem’s boundary conditions? 8

A. Given these various issues with several of the conditions, I believe the inaccurate 9

assumptions set forth in Mr. Zakem’s “boundary conditions” severely weaken his 10

proposals that follow and which are based upon his “boundary conditions.” Mr. Zakem 11

has put forth these conditions as givens, and assumes that the implementation of Section 12

6w of Act 341 must follow them. As I have explained, at least three of the five are either 13

irrelevant or incorrect. Mr. Zakem says on page 23, line 14, of his testimony that 14

Consumers Energy’s plan to implement Section 6w of Act 341 has “faults” because it 15

does not meet the conditions that he believes should be imposed on this entire case. 16

Mr. Zakem then sets out designing an entirely new arrangement completely divorced 17

from the actual terms of Section 6w of Act 341. But given the issues in the conditions, 18

(1) his assertion that Consumers Energy’s plan has faults is incorrect, and (2) his lengthy 19

attempt to re-legislate Act 341 through his alternative proposal is neither appropriate nor 20

reasonable. 21


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ENERGY MICHIGAN’S ALTERNATIVE PROPOSAL 1

Q. Is Mr. Zakem correct in asserting on page 23, line 1, of his testimony that the SRM 2

capacity charge should be forward looking? 3

A. No. I addressed this earlier when discussing Mr. Makholm’s testimony on this issue; 4

Section 6w(3)(a), in describing how the capacity charge should be calculated, directed the 5

utility to, “include the capacity-related generation costs included in the utility’s base 6

rates, surcharges, and power supply cost recovery factors, regardless of whether those 7

costs result from utility ownership of the capacity resources of the purchase or lease of 8

the capacity resource from a third party.” There is nothing in that statutory language that 9

suggests that Consumers Energy’s calculations should be forward-looking or incremental, 10

as suggested by Mr. Zakem. 11

Q. Does Mr. Zakem correctly describe Consumers Energy’s proposal for a 30-year capacity 12

charge term on page 24, line 2, of his testimony? 13

A. No. Mr. Zakem says that it would be a 30-year obligation for paying historic embedded 14

costs. As I described in detail in my direct testimony, the 30-year proposed term is 15

designed with the specific anticipation that new capacity will need to be developed in 16

order to serve load. To the extent that historic costs are included in the rate itself, I have 17

already discussed how (1) that is what is directed by Section 6w(3)(a); and (2) 18

Consumers Energy uses all of its capacity resources to meet its obligations, and will 19

continue to use existing resources to meet obligations in the future. The fact that 20

Consumers Energy uses all of its capacity resources in a holistic manner obviates 21

Mr. Zakem’s suggestion on page 24, line 10, through page 25, line 2, that only 22

incremental capacity should be considered in the capacity charge. 23


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PROVISION OF ENERGY SEPARATE FROM CAPACITY 1

Q. Is Mr. Zakem correct is his characterization, on page 24, line 3, of his testimony that 2

Consumers Energy’s proposal results in a “separation in provision of energy and 3

capacity, where a retail customer could have one LSE providing capacity and another 4

providing energy?” 5

A. Yes, he is correct, because this situation is specifically contemplated by Section 6w of 6

Act 341. The statute clearly allows for an AES to provide capacity to its customers if it 7

has the capacity to offer, but requires the AES’s customers to receive capacity from the 8

utility if the AES does not demonstrate adequate capacity, even while the customers may 9

continue purchasing energy from the AES. 10

PEAK LOAD CONTRIBUTION 11

Q. Is Mr. Zakem correct when he says, on page 25, line 19, of his testimony, that “Electric 12

Choice customers do not contribute to the monthly peak demands during the summer 13

months?” 14

A. No. It is not at all clear how this could be the case. In fact, the logic behind MISO’s 15

PLC process is that ROA customers do contribute to peak demand, and the PLC process 16

exists to determine how much they contribute. Therefore, Mr. Zakem’s suggestion that 17

capacity production costs should not be allocated to ROA customers is without merit. 18

SUFFICIENCY OF CAPACITY TO ACHIEVE THE LCR 19

Q. Are Mr. Zakem’s assertions on page 34 regarding LCR in LRZ 7 correct? 20

A. I do not believe so. Mr. Zakem believes that LRZ 7 will continue to easily meet its LCR, 21

but as I have already noted, the Commission’s July 31, 2017 Order in Case No. U-18197 22

found that LRZ 7 is at risk of falling short of meeting its LCR in the near future, an 23

assessment that is corroborated by the most recent MISO OMS Survey which is my 24


rte0817-dfr 34

Exhibit A-23 (DFR-7). Mr. Zakem further believes that, since utilities will ensure that 1

the LCR is met for their own bundled load, no further action is needed, saying that “LCR 2

can be covered by normal utility capacity planning.” But utilities do not currently plan 3

for ROA load – the very issue that Section 6w of Act 341 was intended to address. 4

Q. Please explain further. 5

A. On page 36 of his testimony, Mr. Zakem explains that since LCR is currently met in 6

LRZ 7, and because utilities will replace retiring capacity in the future, LCR will always 7

be maintained, so the only question is how to pay for the incremental replacement 8

capacity. But this is inaccurate. Consumers Energy will indeed replace capacity that 9

retires, but it will not necessarily do so on a MW-to-MW basis. For example, if 10

1,000 MW of capacity is retired, and Consumers Energy’s integrated resource planning 11

determines that only 900 MW of replacement is needed to ensure that Consumers 12

Energy’s bundled customers are planned for, then the amount of capacity will decline by 13

100 MW. If there was no ROA load, that would be a good outcome, because 14

overcapacity would be reduced. Since ROA load does exist, excess capacity that 15

currently ensures that LCR is met for the ROA load would no longer be available in this 16

example. Additionally, the utility may find that it is economically beneficial to replace 17

some capacity from locations outside of LRZ 7. In those situations excess capacity that 18

currently ensures that the LCR is met for ROA load would no longer be available as well. 19

Therefore, Mr. Zakem’s claim that LRZ 7 faces only financial questions, and not 20

reliability ones, is incorrect. 21


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CERTIFICATE OF NEED PROCESS 1

Q. Regarding Mr. Zakem’s proposal that any incremental capacity be approved by the 2

Commission in a certificate of necessity (“CON”) process before it can be included in the 3

“cost sharing” that he would use for the capacity charge, is that reasonable? 4

A. No. Requiring a CON is unnecessarily onerous, and the suggestion that a CON be 5

required in order for a utility to obtain compensation for capacity it builds or purchases to 6

serve customers does not reflect the regulatory construct in Michigan A CON process is 7

only one of many means by which a utility may obtain Commission approval for cost 8

recovery for a generating asset. Mr. Zakem’s proposal, in addition to not reflecting the 9

terms of Act 341, is artificially narrow and restrictive regarding the manner in which the 10

utility could obtain cost recovery approval for future capacity resources. 11

ACT 341 CONSTRUCT 12

Q. Do you believe that Mr. Zakem’s general proposal for SRM implementation, beginning 13

on page 37 of his testimony, is reasonable? 14

A. No. For one thing, Mr. Zakem is proposing an arrangement that only considers the role 15

of incremental capacity in meeting capacity obligations, ignoring the role that existing 16

capacity plays and will continue to play in meeting capacity obligations. In general, 17

Mr. Zakem is trying to create an entirely different construct than that established by 18

Section 6w of Act 341. 19


rte0817-dfr 36

Q. In his testimony, including on page 47, line 13, Mr. Zakem suggests that there is a 1

conflict between Section 6w(3) of Act 341 and a different statute, MCL 460.11(1). Do 2

you believe there is a conflict? 3

A. I do not believe so. Mr. Zakem notes that MCL 460.11(1) requires that rates be 4

established equal to the cost of providing service to each customer class. Consumers 5

Energy’s proposal has done that, following the instructions of Section 6w(3), as I have 6

already discussed, to ensure that ROA customers who pay the capacity charge are paying 7

for the capacity that they receive. There is nothing in MCL 460.11(1) that should suggest 8

that a capacity charge should only consider incremental capacity. Mr. Zakem’s argument 9

that MCL 460.11(1) does imply this, and his argument that it is in conflict with Act 341, 10

both seem to be based on his assertion on page 48, line 1, of his testimony, that 11

Consumers Energy “is not going to use its existing resources to provide for additional 12

capacity obligations, and therefore the cost of existing resources may not be relevant.” 13

As I have already said, this argument is incorrect, because Consumers Energy uses all of 14

the capacity resources in its portfolio to meet its load obligations holistically. 15

ENERGY MICHIGAN’S EVALUATION OF MISO CAPACITY SITUATION 16

Q. Is Mr. Zakem correct in his argument that “Something is working that is providing more 17

capacity, even if we don’t understand why,” as he asserts on page 54 of his testimony? 18

A. No, and his statement reflects a simplistic and risky view of the need (or lack thereof) to 19

take action pursuant to Act 341 to ensure the reliability of the electric grid in Michigan. 20

Mr. Zakem alludes to the fact that previous MISO OMS Surveys have projected future 21

shortfalls in capacity that ultimately did not occur, suggesting that “something” unknown 22

is solving the problem in a mysterious way. As Mr. Zakem acknowledges, MISO has 23


rte0817-dfr 37

refined its survey over time to take into account more capacity resources that are likely to 1

be built, and that has had the effect of reducing many of these previously-predicted future 2

shortages. But contrary to Mr. Zakem’s professed lack of knowledge, there really is no 3

mystery: most MISO LRZs are fully regulated, and the LSEs in those LRZs had 4

integrated resource plans with their state regulators that ensured replacement capacity 5

would be added as necessary to serve loads. The one MISO LRZ that is deregulated – 6

LRZ 4 in southern Illinois – has a very high Capacity Import Limit and therefore a very 7

low LCR, meaning it can import relatively large amounts of capacity without 8

compromising reliability, unlike LRZ 7, which has a relatively high LCR with a 9

correspondingly low Capacity Import Limit. In any case, even accounting for the 10

refinements to the MISO OMS Survey methodology, LRZ 7 is still shown to be at risk 11

for not meeting its LCR by 2022. This should not be a surprise; utilities in LRZ 7 are 12

going to go through an integrated resource plan process starting in 2019 which will help 13

ensure that they can serve their bundled customers, but this will not cause them to ensure 14

they have capacity to serve ROA load. In short, we know what causes capacity to be 15

built in most MISO LRZs, and we know that there are still issues of a capacity shortfall 16

on the horizon for LRZ 7, which the Commission acknowledged in its July 31, 2017 17

Order in Case No. U-18197. 18

Q. Is Mr. Zakem correct in his argument on page 55 of his testimony that “low growth 19

means no surprises?” 20

A. In this paragraph, Mr. Zakem is returning to the point that utilities will replace any 21

retiring capacity to ensure that they can serve their bundled customers, and since LRZ 7 22

currently meets its LCR, it will therefore continue to meet it. As I have previously 23


rte0817-dfr 38

discussed, utilities that only plan to serve their bundled customers might “right-size” their 1

capacity portfolios by only replacing the capacity that is needed to serve the bundled 2

customers, eliminating the excess that could potentially serve ROA load. This potential 3

outcome should indeed not be a surprise to anyone, but Mr. Zakem is nevertheless 4

incorrect in his supposition that utility planning for bundled customers will continue to 5

provide enough capacity for ROA load as well. 6

FEDERAL ROLE IN ENSURING RESOURCE ADEQUACY 7

Q. Is Mr. Zakem correct in his description on pages 56 and 57 of his testimony regarding 8

who has a legal responsibility to ensure reliability? 9

A. Mr. Zakem is not correct when he says that “for Zone 7 in Michigan MISO governs 10

reliability,” as though that were the entire story. MISO certainly does use PRMR and 11

LCR to help ensure resource adequacy, and Consumers Energy has argued for their 12

incorporation into SRM implementation, and MISO has well-defined reliability roles 13

related to management of the transmission system. But the Commission in particular and 14

the State of Michigan in general have ultimate jurisdiction over resource adequacy for 15

retail electric markets within the state. 16

Q. What about Mr. Zakem’s description of the North American Electric Reliability 17

Corporation (“NERC”)? 18

A. Mr. Zakem’s description is inaccurate on several points. First, he states that “MISO is 19

part of [NERC].” That is not true; MISO is subject to NERC standards, as is Consumers 20

Energy, but MISO is an independent organization and is certainly not part of NERC. 21

Second, Mr. Zakem misunderstands NERC’s role in ensuring reliability. NERC 22

establishes reliability standards, under the general guidance of FERC and subject to 23


rte0817-dfr 39

FERC approval. Those reliability standards cover far more than resource adequacy, 1

which is again ultimately a state issue. Regional transmission operators, such as MISO, 2

then implement measures to ensure that those reliability standards are met. One example 3

of this is MISO’s use of LCR and PRMR to ensure that the 1-day-in-10-year LOLE 4

standard is maintained. In that way, NERC (and FERC) are ultimately responsible for 5

maintaining general “reliability,” with the caveat that there is a state role for resource 6

adequacy. But when Mr. Zakem says on page 57, line 1, of his testimony, “So if the 7

question is asked in the context of ‘who is paying attention to reliability,’ then the answer 8

is that there are regional, national, and federal organizations whose responsibility is to 9

maintain electric reliability,” he is incorrect. His statement suggests that FERC, NERC, 10

and MISO actively manage resource adequacy to ensure that there is never a shortfall, 11

and that is not true. None of those organizations intervene to prevent capacity resources 12

from being retired, nor do any of them act to cause new resources to be developed. In 13

MISO, if a capacity resource owner plans to retire a generator, that retirement is reviewed 14

by MISO under Attachment Y of the MISO Tariff, but that review is only intended to 15

ensure that the retirement will not cause electrical instability on the transmission grid, not 16

to ensure that generation resource adequacy will be maintained. 17

Q. Do you agree with Mr. Zakem’s contention on page 58 of his testimony that there is no 18

logical reason to believe that there is no basis for acting as if there will not be enough 19

capacity in MISO to ensure resource adequacy for the foreseeable future, “given what we 20

know today?” 21


rte0817-dfr 40

A. No. As I have discussed, the MISO OMS Survey shows a likelihood that LRZ 7 will not 1

be able to meet its LCR by 2022, and the Commission came to the same conclusion in its 2

July 31, 2017 Order in Case No. U-18197. 3

SRM TERM LENGTH AND THE MISO TARIFF 4

Q. Does Mr. Zakem have valid concerns regarding the length of the SRM term as opposed to 5

the provisions of the MISO Tariff, as he discussed on page 62 of his testimony? 6

A. No. The SRM is a state-level process that has been established to allow the Commission 7

to manage and ensure generation resource adequacy in Michigan, a retail electric market 8

that is under the Commission’s jurisdiction. The SRM is designed to complement 9

MISO’s resource adequacy process, which it does by requiring LSEs within Michigan to 10

anticipate future MISO planning years in addition to the prompt year. That is no different 11

than integrated resource planning that is used by many states, including MISO states, to 12

ensure that LSEs within those states will have adequate capacity well beyond the time 13

horizons of their respective independent system operators. I have already discussed why 14

the SRM process needs to be in place indefinitely; I will reemphasize that it is the SRM 15

process that should be indefinite. Mr. Zakem’s characterization on page 62, line 15, of 16

his testimony as an indefinite capacity requirement is not an accurate characterization. 17

CONCLUSION 18


A. Yes. 20



In the matter, on the Commission’s own motion, ) to open a docket to implement the provisions of ) Section 6w of 2016 PA 341 for ) Case No. U-18239 CONSUMERS ENERGY COMPANY’S ) service territory. )

)

EXHIBITS

OF

DAVID F. RONK, JR.

ON BEHALF OF


August 2017

1

Lawrence Makovich

IHS VP and Chief Power Strategist

Michigan Senate Energy and Technology Committee Meeting Testimony

September 17, 2015

I am Lawrence J. Makovich, IHS Vice President and Chief Power Strategist. I am also currently a Senior

Fellow at the Mossavar-Rahmani Center for Business and Government in the John F. Kennedy School of

Government at Harvard University. I have been involved in electric power industry research for over

thirty years while working at National Economic Research Associates, DRI, Cambridge Energy Research

Associates and IHS. My research focuses on electricity markets, regulation, economics, and strategy. I

have testified numerous times before the US Congress on electric power policy. I have advised the

government of China on electric power industry restructuring and testified before the Brazilian Congress

on power liberalization. I have examined the impact of deregulation on residential power prices and the

development of resource adequacy mechanisms in the CERA Multiclient Studies Beyond the Crossroads:

The Future Direction of Energy Industry Restructuring, and Bridging the Missing Money Gap: Assessing

Alternative Approaches. Among other significant research efforts are examinations of the California

power crisis in Crisis by Design: California's Electric Power Crunch and Beyond California's Power Crisis:

Impact, Solutions, and Lessons. I have been a lecturer on managerial economics at Northeastern

University's Graduate School of Business. I hold a BA from Boston College, an MA from the University of

Chicago, and a PhD from the University of Massachusetts.

I testified before the Michigan House Energy Committee on March 18, 2015 regarding the problematic

misalignments in the current hybrid electric industry structure. I recently completed a study for DTE

Energy entitled "Meeting the Michigan Power Sector Challenge" that focused on these problems and

some potential available solutions.

I understand that Committee Chairman Nofs introduced Senate Bill 437 to change the rules

governing the provision of electric services to customers from alternative electric suppliers. I

want to share my thoughts today on why these changes are a good idea.

The current hybrid Michigan power industry organization

Partial retail open access was never the intended end state for deregulation. It exists because

Michigan's deregulation stalled half way along the move from regulation to deregulation. That

happened because power deregulation did not work as expected.


Case No.: U-18239Exhibit: A-21 (DFR-5)

Witness: DFRonkDate: August 2017

Page 1 of 43

2

Michigan currently faces a power sector challenge because the current partial retail open

access increases the probability for electric reliability problems and also produces an unfair

distribution of power supply costs among consumers.

The probability is increasing for a power supply shortfall in Michigan's Lower Peninsula within

the next few years. The current pipeline of power supply in Michigan does not look big enough

to keep up with demand growth and power plant retirements. The most recent regional electric

reliability assessment projects a 1,200 to 1,300 megawatt power supply shortfall to meet the

expected MISO Zone 7 peak load of over 21,000 Mw in 2016.1 The assessment indicates

regional surpluses and transmission transfer capabilities can address zonal deficits through

2019. The problem is that MISO Zone 7 capacity prices are not signaling the need to invest

when a capacity shortfall is expected within less time than the time required to site, permit and

build new power supply. The MISO assessment concludes that additional actions are needed to

ensure sufficient resources beyond 2019.

The current hybrid electric industry structure in Michigan does not distribute the costs of the

power system fairly. All Michigan power consumers-retail open access or utility ratepayers

alike-get their electricity from the same source of supply-an integrated regional power

system. Yet, retail open access customers pay a smaller share of the costs compared to utility

ratepayers. Current misalignments in the Michigan hybrid power sector shift several hundred

million dollars per year of costs away from a minority of Michigan retail open access consumers

(accounting for little over 10 percent of the state's power consumption) to the majority of

customers who remain utility ratepayers. This advantage has not gone unnoticed. As of January

2015, 5,227 customers of DTE and 5,754 customers of CMS are in the queue to acquire these

advantages through the existing retail open access program.

To understand why changes to the current hybrid are needed, it is important to know why

Michigan deregulation stalled and produced the current hybrid power industry structure with

these challenges.

Michigan stalled halfway between regulation and deregulation

Twenty years ago, the idea gained traction that a deregulated power industry relying more on

market forces, would perform better than the traditional industry structure relying heavily on

regulatory processes. "Competitive, deregulated, liberalized or restructured" electricity industry

constructs have been tried with a variety of different models and have proven to be

problematic.

1 2015 OMS MISO Survey Results, July 2015

Case No.: U-18239 Exhibit: A-21 (DFR-5)

Witness: DFRonk Date: August 2017

Page 2 of 43

3

The original plan for deregulation was to give all retail consumers the ability to shop around

and choose their power supplier-retail open access-including a new set of alternative electric

suppliers (AES) that would aggregate customer power needs and buy power from the

marketplace on their behalf. On the supply side, the plan was to unbundle utilities-separating

the generation business from the transmission and distribution businesses. The goal was to

increase competitive forces by instituting bidding for power supply among rival generators with

a regulated power grid operated by an independent system operator providing the

coordination to enable market interactions between buyers and sellers.

Most restructuring plans reflected a simple faith that the marketplace would work like the

economics text book example and produce the desired results-

Reliability-the energy market would produce market-clearing prices that would balance

demand and supply in the long run.

Efficiency-an energy market would clear on the basis of short run marginal costs and produce

an efficient utilization of available supply options.

Diversity-the level and variability of energy market cash flows would pay for a cost effective

mix of demand side resources, peaking, cycling and base load plants of varying fuel and

technology types.

Environmental compliance-coordinated environmental policy would internalize

environmental costs into the marketplace.

Power industry restructuring did not play out as planned.

California was on the leading edge in the US to implement this type of plan when it passed

legislation to deregulate power in 1996, four years ahead of Michigan passing its Public Acts

(PA) 141 and 142 to deregulate its power sector.

California ISO and power exchange began operating an energy only market design in 1998.The

Michigan and MISO plan was similar to the California plan. Michigan's regional power system

MISO began operating an energy only market deregulation plan in 2005.

When California began operating its energy marketplace in 1998, the power system had a

surplus of generating capacity. As expected, market produced prices that were too low to

provide the necessary cash flows to support new power supply investment. But as time passed,



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4

an unexpected result began to emerge. The low wholesale power prices persisted even when

demand and supply were in balance with the desired reserve margin. This California electric

energy market result was at odds with the economics textbook model of a competitive

marketplace. As the California economy expanded and power demand increased further,

wholesale energy prices remained below the average total cost of new supply.

California's chronically low prices caused a lack of new power supply entry and thus,

underinvestment in power supply. The inevitable consequence was a severe power shortage

with dramatic wholesale power price spikes and rolling blackouts. Making matters worse were

attempts by some power traders to profit by taking advantage of shortage conditions.

The problem of chronically low market power prices was not unique to California. The root

cause was that the technologies employed to cost-effectively generate electricity did not have

the characteristics needed to produce a textbook market outcome. This problem is known as

the "missing money problem."2 The problem stems from the characteristics of power

generation supply technologies.

Besides this market flaw inherent to power generation technologies, public policies introduced

another market distortion through mandates for renewable power and renewable subsidies

based on output. These market interventions depress depress market cash flows-on the

revenue side, these interventions suppress the level of wholesale prices and on the cost side,

these interventions increase costs because cycling power plants have to start up, ramp up and

down and shut down more frequently to backup and fill in for the intermittent pattern of

renewable power generation.

Some people misinterpret low power prices as the result of the entry of more efficient new

competitive suppliers. The evidence does not support this interpretation that deregulation

caused new suppliers to win and existing suppliers to lose. The competitive generation business

did not produce winning results--the expected growth and profitability did not materialize. The

missing money problem caused competitive generating companies to write-down assets, sell

power plants at substantial discounts to cost, and in many cases undergo bankruptcy

reorganizations. About S GW of Michigan's total 30 GW of power supply was originally built by

competitive generators. The competitive generating companies owning three quarters of this

supply went through bankruptcy since deregulation began; National Energy and Gas

Transmission (a unit of PG&E) and Mirant in 2003, and Dynergy in 2011. Financial distress

2 The term "missing money" was first used to describe fixed cost recovery in power by Cramton and Stoft in their

2006 paper "The Convergence of Market Designs for Adequate Generating Capacity," written for CAISO's

Electricity Oversight Board.



Page 4 of 43

5

forced the sale of a majority of these power plants at a significant discount to the net cost. As a

result, half ofthe generating capacity built by competitive generating companies in Michigan

was sold and is now owned by regulated utilities. In the past decade, competitive generators

have not built any conventional generating power plants in Michigan.

The missing money problem is a problem for existing as well as new power plants. In particular,

renewable power mandates suppress market clearing energy prices and disproportionately

reduce the cash flows of baseload power plants. As a result, critical power supply assets are

closing down before it is economic to do so. These premature power plant retirements are not

in the best interest of the public because their replacements are more expensive than their

continued operation. In addition, depressed market cash flows aggravate the reliability

challenge by encouraging uneconomic premature retirement of capacity. For example,

Dominion Resources decided to retire the 556 MW Kewaunee nuclear power plant because the

market provided cash flow of around 40 $/MWh and going forward costs required cash flows

closer to 55 $/MWh. This baseload capacity is being replaced with new supply costing 70

$/MWh.

Kewaunee is not an isolated example. Vermont Yankee is another case where chronically low

cash flows triggered a baseload power plant closure that would have been less expensive to

keep running than to replace. In Ohio and Illinois, proposed changes are under consideration to

provide contractual payments to base load generators rather than allow market cash flows to

trigger premature closures. The counterparties to these contracts are regulated utility

ratepayers which will create a de facto move back toward regulated cost recovery in order to

ensure reliability.

The inherent technology flaw and unintended consequence of renewable mandates are

obscure market problems. As a result, a consensus did not form quickly regarding what had

gone wrong or what had to be done to avoid these problems elsewhere. Consequently,

industry restructuring lost momentum and most electricity restructuring efforts stalled.

Following the California power crisis, seven states passed legislation to suspended power

restructuring efforts and others passed legislation to alter deregulation plans.

Michigan's Public Service Commission began altering its deregulation plan by initiating its own

study of the evolving power sector. The Public Service Commission Chairman Peter Lark

released the "Michigan's 21" Century Electric Energy Plan" in January, 2007. The Michigan

Legislature responded to the report's recommendations and altered the course of electricity

industry restructuring with the passage of Public Act 286 and 295 in 2008. These new laws

made four major changes:



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6

1. Freeze retail open access--the plan to eventually have 100 percent of customers with

retail open access was changed to limit choice to just customers involved in iron ore

mining and processing along with 10% of the remaining average weather normalized

retail electric load.

2. Halt utility unbundling--The process of requiring utility divestment of generation assets

ended.

3. Establish utility Integrated Resource Planning-- utilities detailed their expected demand

and proposed supply actions, including commission approval of a Certificate of Need for

new generating capacity, before commencing construction.

4. Mandate renewable power supply. This market intervention overrode the market

result and imposed a minimum percentage of power supply from renewable power

sources.

The shortcomings of deregulation forced power market institutions to change market rules. The

California ISO made structural adjustments after recognizing that the state's efforts to

prosecute law-breaking power traders and recover the ill-gotten gains of the power crisis did

not address the root cause ofthe California power shortage. California ISO instituted a resource

adequacy rule in 2004 that became binding in 2006. This new rule required all load serving

entities to have enough capacity to meet their customers aggregate demand plus a minimum

reserve margin. This rule created a demand for capacity that enabled an informal capacity

market to arise. An informal marketplace does not organize market interactions but rather

relies on capacity buyers and sellers to seek each other out for transactions. The resulting

contract prices, terms, and conditions were typically known only to the contract counterparties

and thus the informal market provided little capacity price transparency.

MISO followed other power systems in addressing power design market flaws by adding a

resource adequacy mandate in 2009. These rules create informal capacity markets but these

markets are not very transparent. Four years after mandating a resource adequacy rule, MISO

enhanced its resource adequacy mandate by implementing a formal capacity market to clear

demand and supply about two months in advance of the annual peak demand.

What MISO is doing now is similar to what PJM was doing in 1997 when it began power

restructuring with a power sector design incorporating both energy and capacity markets right

from the start. However after five years of experience with its formal capacity market like what

MISO has in place now (known as the "capacity credit market"), PJM found that this market

design produced a boom and bust capacity price pattern and concluded the power supply

investment price signal could be improved by reducing its volatility. PJM responded by evolving

its formal capacity market into a formal forward capacity market that cleared projected

capacity demand and supply three years in advance with a payment commitment term of one



Page 6 of 43

7

to three years. In addition, the volatility of the capacity pricewas further limited by instituting a

managed capacity demand curve and applying more stringent bidding rules to establish the

capacity supply curve.

Missing money problem still exists-market based cash flows still fall short of covering the costs of the power system we want.

The current MISO capacity market design is prone to producing boom and bust prices.

Capacity markets are designed to only cover the costs necessary to prevent shortages.

Reliability cost benchmark-a peaking unit--the MISO Zone 7 CONE is $90.1 per KW per year

and the Net CONE is $65.1 per KW per year.3 The difference between the MISO CONE and Net

Cone shows that even for a peaking power plant with an expected low utilization rate, the

contribution from energy market cash flows are important and cover over one-third of annual

carrying charges of the upfront investment costs.

The market-clearing MISO Zone 7 capacity price for the summer of 2015 was $1.27 per KW per

year. To put this into perspective, the current MISO capacity prices only cover around 2 percent

of the Net CONE benchmark cost. This indicates that market prices are currently in the bust

phase of a capacity price cycle. A boom and bust pricing pattern is evident in MISO. In the most

recent capacity auction, the market clearing price of capacity in MISO zone 4 was almost 10

times higher price than the previous year's auction result.

If the MISO formal capacity market produces the intended result-capacity prices that average

to a price that equals the average total cost of new capacity in the long run (net of energy

market margins)-then the booms have to be high enough to make up for the busts over the

life of the generating capacity. If boom and bust prices each prevail roughly half of the time,

then prices would have to be a multiple of the Net CONE in the boom phase to produce an

average across all years equal to Net CONE.

Retail open access options shift capacity cost burdens

The combination of boom and bust pricing patterns for MISO Zone 7 capacity plus the

wholesale energy price correlated to volatile natural gas prices patterns make the market costs

of power (the sum of market capacity and energy prices) significantly more variable through

3 MISO Locational Resource Zone Cost of New Entry Filing to the Federal Energy Regulatory Commission,

September 3, 2013.



Page 7 of 43

8

time compared to the regulated costs of power. The unintended consequence of halting retail

open access at 10 percent of power demand is the provision of a valuable option to some

customers but not others. A combination of a boom phase in the capacity market and cyclical

highs in natural gas prices can trigger retail open access customers to switch power suppliers in

an effort to always the lower of regulated and AES prices at any given point in time. As a result,

consumers with an option to switch can avoid paying their share of capacity costs by timing

their switching activity between AES and regulated utilities.

Short run switching options hinder balancing demand and supply in the long run

The introduction of the MISO capacity market was intended to address the inherent missing

money problem at the root of power market reliability problems. However, the ability for

customers to switch suppliers in the short run creates uncertainty regarding who is responsible

to plan for their power supply in the long run. The current problem is that capacity prices are

not moving into the boom phase and producing an investment price signal far enough in

advance of shortage conditions to allow for the lead time for power plant development. Under

these conditions, when market-sourcing power suppliers try to pass on the booming capacity

prices to retail open access customers, these customers will face a strong economic incentive to

switch back to regulated power provider and pay the lower capacity rates that reflect the

average embedded historical capacity cost. As the projected power supply shortfall draws

closer, the probability grows that utilities will not have sufficient time to reliably meet this

increase in regulated customer demand.

The margin for error in balancing power demand and supply is small. In Michigan, a reserve

margin between 14 and 15 % is required to reliably balance power demand and supply.

Dropping just 5 percent short of the target reserve margin substantially increases the

probability of serious power system problems-emergency load shedding, brownouts, and

price spikes altogether similar to what happened in California in 2000-2001.

In 2006, the Michigan Public Service Commission (MPSC) looked ahead and projected an

electric demand and supply balance in the near future but an insufficient pipeline of new supply

under development for subsequent years. Shortly after the MPSC reliability assessment, the

business cycle produced an unanticipated temporary reprieve from the impending power

supply shortfall in the Lower Peninsula. At the end of 2007, the most severe economic

downturn since the Great Depression began. Reduced business activity and lower household

purchasing power reduced power demand. The economic downturn dropped Michigan peak

power demand by over 3,000 MW (December 2007 to June 2009).



Page 8 of 43

9

System-wide benefit free riders

Michigan utility ratepayers create overall system benefits funding investments in demand-side

management, production efficiency (peaking, cycling and base load), risk management, and

mitigation of environmental impacts. Since utility-owned power plants participate in the

market, these benefits spill over to the market outcome and produce cleaner, more cost

effective and less volatile market clearing power prices.

The problems in deregulated electricity markets are reducing power supply diversity.

Investments in production efficiency and production cost risk management produce a big

payoff. For example, if Michigan power supply lacked fuel and technology diversity and relied

on a single fuel and technology--only natural gas-fired combustion turbines for power supply-

then the wholesale price of power in the state of Michigan from 2010 to 2013 would have been

over 50% higher, with a monthly price variation would have been over three times greater than

the actual level and variations in market-clearing prices.

The costs of environmental controls at utility power plants provide benefits to all customers yet

the costs are often borne by just the regulated consumers. This uneven cost burden may

increase when Michigan develops within the next several years, its state implementation plan

for the EPA final rule in the Clean Power Plan. This unfair cost burden will arise ifthe costs of

utility actions to achieve compliance are borne by ratepayers while the benefits of achieving

the statewide C02 emission goals are shared across all consumers in the state.

In regulated utility rates, non-variable generating costs reflect the average historic embedded

cost of capacity in the utility generatioo portfolio. The component of the regulated price

covering the average cost of capacity ranges from 3 to 4 cents per kWh across different

customers classes. This translates into a Michigan regulated capacity charge of about $200 per

kW per year. Roughly one third of the regulated embedded capacity charge covers the cost of

investments to provide reliability and the other two-thirds covers the cost to provide the

production efficiencies through a mix of peaking, cycling, base load and demand side resources

as well as provide risk management through a diverse fuel and technology supply mix and also

provide the environmental impact management from compliance with existing environmental

regulations.

Retail open access customers are free riders because the system-wide benefits funded by

ratepayers cannot be excluded from customers choosing to be served by market sourced power

suppliers.



Page 9 of 43

10

Conclusion

The current Michigan hybrid power industry structure is not delivering the desired results.

Reliable service-- Short run switching available to retail open access customers creates

uncertainty and insufficient lead times to adequately develop long run power supply. In

addition, the option provides a way for retail open access customers to avoid paying the full

cost of reliability.

Efficient generation--The MISO energy market produces an efficient short run utilization of

available generation resources but energy market interventions suppress the energy market

cash flows needed to support an efficient mix of peaking, cycling and base load power plants in

the long run.

Diverse power supply-market interventions that depress energy market cash flows are not

supporting a cost-effective combination of demand side resources, peaking, cycling, base load

and renewable resources. Nevertheless, utility ratepayers fund the current diverse portfolio

that provide system-wide benefits and thus provide a free ride for retail open access

customers.

Environmentally compliant production-Market cash flows do not cover most of the costs of

environmental control. Again, utility ratepayers fund investments that provide system-wide

environmental benefits and thus provide a free for retail open access customers.

Realigning Michigan regulations and the marketplace.

Two options exist to realign Michigan regulations and the marketplace.

Phase out partial retail open access-the most straightforward realignment option

involves phasing out retail open access by mandating a shift back to utility supply in the

next few years when demand and supply come into balance and capacity prices are

poised to move into a boom phase of the pricing cycle. Moving Michigan away from the

hybrid and back to universal regulation can eliminate the free rider problem in power

cost recovery which is especially important at a time when the state will need to incur

significant costs to comply with the Clean Power Plan.

Alter partial retail open access-with two major revisions. First, a surcharge needs to be

added to the purchased power charges to eliminate the free rider problem and level the

burden of recovering the costs of utility investments that provide system-wide

Case No.: U-18239Exhibit: A-21 (DFR-5)

Witness: DFRonkDate: August 2017

Page 10 of 43

11

efficiency, risk management, and environmental benefits. Second, retail open access

consumer commitments need to be extended to align with a power plant investment

horizon. The goal is to create purchased power agreements with a long enough term to

support a stable environment for power plant investment. In addition, the expiration

dates of customer supply commitments ought to be staggered to limit potential demand

swings in any given year.

The sooner Michigan addresses the problems of the status quo--uneven cost burdens, the

unfair switching option and the increasing probability for power supply shortage, the sooner

Michigan can insure its power system remains reliable, efficient and environmentally

compliant. Corrective actions will enable a fair distribution of costs to customer classes and

maintain the competitiveness of electric input costs to Michigan businesses operating in the

global economy.



Page 11 of 43

IHS ENERGY

Meeting the Michigan Power Sector Challenge

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Page 12 of 43

IHS Energy I Meeting the Michigan Power Sector Challenge

Contents

Executive summary 6 Deregulation: The gap between expectations and reality 6 Creating the hybrid power industry structure 7 The opportunity to realign regulation and the market 9 Conclusion 10

Michigan's electric power industry structure: An unplanned hybrid 11

Inherent and imposed power market flaws produce a missing money problem 12

Altering power deregulation plans 14

Regulated utility rates include full power supply cost recovery 16

Evolving market designs still produce power supply cost recovery shortfalls 17

An uneven playing field for retail open access competition 17

Systemwide benefit for free riders 19

Market prices for energy and capacity vary more than regulated prices 20

A discriminatory retail open access option-confirmed by consumer actions 21

Short-run switching options hinder balancing demand and supply in the long run 22

The current opportunity to realign Michigan regulatory processes and market realities 25 Phasing out partial retail open access 26 Altering partial retail open access 27

Conclusion 27

Appendix: MISO capacity market design produces a boom-and-bust price pattern 29

IHS™ ENERGY Copyright notice and legal disclaimer © 2015 IHS. No portion of this report may be reproduced, reused, or otherwise distributed in any form without prior written consent, with the exception of any internal client distribution as may be permitted in the license agreement between client and JHS. Content reproduced or redistributed with IHS permission must display IHS legal notices and attributions of authorship. The information contained herein is from sources considered reliable but its accuracy and completeness are not warranted. nor are the opinions and analyses which are based upon ft, and to the extent permitted by law, IHS shall not be liable for any errors or omissions or any loss, damage or expense incurred by reliance on information or any statement contained herein. IHS and the IHS logo are trademarks Of IHS. For more information, please contact IHS at www.ihs.com/CustomerCare.

© 2015 IHS 2 •

July 2015



Page 13 of 43


Authors

Project Director Lawrence J. Makovich Vice President and Senior Advisor for Global Power, IHS Energy

Project Team Barclay Gibbs Senior Director North American Power, IHS Energy Project Manager

Leslie Martin Senior Principal Researcher, IH.S Energy

Aaron Marks Senior Research Analyst, IHS Energy

Acknowledgments We extend our appreciation to DTE Energy, which supported this research.

© 2015 JHS 3

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July 2015



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© 2015 lHS 4 July 2015



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Executive summary Michigan faces a power sector challenge because of problematic misalignments in the current hybrid industry structure. This current hybrid ofregulation and markets was never the intended end state of deregulation. Rather, the hybrid came about because power deregulation did not unfold as planned.

Michigan power deregulation began 14 years ago. As Michigan began implementing its power restructuring plan, the problematic realities of power industry restructuring efforts elsewhere were coming to light. In particular, the gap between the expectations and the reality of deregulation became increasingly apparent in California, where the restructuring process had begun about seven years ahead of Michigan. A serious shortage developed in California because power markets failed to produce prices high enough to cover the average costs of power generation; and as a result, power supply investments did not keep pace with customer needs.

The tendency of competitive power markets to leave a gap between market-clearing prices and average total costs is known as the "missing money problem." 1 The missing money problem has three major consequences. The first is the risk of underinvestment in new power supply. Second, low prices cause too many existing power plants to be retired early, even though their continued operation would be far less costly than replacing the supply they provide. Third, low prices distort market signals and lead to an inefficient mix offnels and technologies. IHS Energy estimates that such inefficiencies are moving the cost offuel used to generate electricity in the United States to a level 9% higher than it should be. ·

There is no one-size-fits-all solution to the missing money problem. We have studied the particular challenge facing Michigan and recommend the following two options:

Phase out partial retail open access. The most straightforward realignment option involves phasing out retail open access by mandating a shift back to regulated utility supply.

• Alter partial retail open access-with two major revisions. First, a surcharge needs to be added to alternative energy supplier (AES) power charges to address the free rider problem and level the burden across all customers for recovering utility investments in systemwide efficiency and risk management. Second, a rule needs to be put in place requiring AESs to demonstrate a firm forward supply arrangement for the projected needs of their current customers to provide enough lead time (at least five to seven years) to develop not only peaking units but also the cycling and baseload power plants necessary for efficient and reliable power supply.

Deregulation: The gap between expectations and reality

The California power crisis exposed the flaws in power market deregulation plans. The cost recovery shortfall that caused underinvestment occurred for two reasons, one inherent in power generation and one imposed by legislative and regulatory interventions. First, power generation technologies have inherent characteristics that prevent an electric energy-only market design from delivering prices high enough to balance demand and supply in the long run. Second, regulations imposed on power supply, including both subsidies and mandated generation shares for renewable power, create the unintended consequence of suppressing energy market prices. Both the inherent and the imposed dimensions of this problem cause a persistent gap between prices and average total costs. This gap prevented deregulated power markets from reaching the stable, economics textbook market result that people had expected.

Markets failing to produce a textbook result owing to an inherent characteristic of the production technology are neither new nor unique to the power business. A nineteenth-century French engineer and economist, Jules Dupuit, analyzed market failure in the railroad industry resulting from the gap between market prices and average total costs.2 Dupuit

1. The term missing money was used to describe fixed-cost recovery in power by Peter Cram ton and Steven Stoft in their 2006 paper, "The Convergence of Market Designs for Adequate Generating Capacity," written for the California Independent System Operator's Electricity Oversight Board.

2. Jules Dupuit, "De l'Influence des Peages sur l'Utilite des Voies de Communication," Annales des Pants etChausstes no. 207, 1849, p. 170-248.

© 2015 IHS 6 July 2015



Page 17 of 43


illustrated the root cause of the problem by developing the example of a bridge-a technology with a large up-front capital cost and thus a positive average total cost, but also a technology with a zero marginal cost for providing bridge crossings. The incremental cost is zero because it costs the bridge owner nothing extra to let someone cross the bridge.3

Dupuit understood that in a marketplace all rival bridge owners would be willing to take any customer payment above zero in order to provide some contribution to their fixed costs. He argued that a market for bridge services would not work because competitive forces would logically drive the market price toward zero. Thus, the market would inherently fail to provide cost recovery and thus fail to attract the investment needed to produce a stable, long-run market result.

Power production technologies have cost characteristics similar to Dupuit's bridges. In particular, wind and solar technologies have significant up-front costs and zero incremental generating costs. More generally, the technologies employed to cost-effectively generate electricity do not have the incremental cost characteristics needed to produce a textbook market outcome in which prices keep demand and supply in long-run balance. Contemporary economists call this the missing money problem. !HS Energy recently completed a study on behalf of a group of industry stakeholdersincluding power system operators, merchant generators, and traditional utilities-concerning the causes, consequences, and solutions to the missing money problem.4 The study found that there is no one-size-fits-all solution to the missing money problem and that several approaches can meaningfully address the problem if they align with power system conditions. The !HS Energy study's research and key findings served as the basis for our current more in-depth study of the challenge facing the Michigan power sector. In this case, the Midcontinent Independent System Operator (MISO) regional power market conditions address some, but not all, of the missing money problem. Therefore, the use of regulated cost recovery to bridge the remaining missing money gap is a logical solution. However, the presence of the current retail open access undermines the effectiveness of this industry structure.

Creating the hybrid power industry structure

The economic impact of the California power crisis of 2000 to 2001 was so severe that it altered power industry restructuring plans not only in California but around the world. Following the crisis, California made structural adjustments to its market rules after recognizing that prosecuting law-breaking power traders and trying to recover the ill-gotten gains of the power crisis did not address the root cause of the shortages. Initially, California employed an ad hoc approach oflong-term power supply contracts. Eventually, California instituted a resource adequacy rule in 2004 that became binding in 2006. The rule required all load-serving entities to have enough capacity to meet their customers' aggregate demand plus a minimum reserve margin. This rule created a demand for capacity and enabled an informal capacity market to arise. An informal marketplace does not organize market interactions but rather relies on capacity buyers and sellers to seek each other out for transactions.

MISO began deregulation with an energy-only market design similar to California's. After California made its rule changes, MISO also altered its rules to include a resource adequacy mandate in 2009. The resource adequacy mandate created an informal capacity market in MISO. Four years after the resource adequacy rule, MISO enhanced the mandate by implementing a formal capacity market to clear demand and supply about two months in advance of the annual peak demand. With this enhanced approach, MISO runs a voluntary capacity auction each April to balance capacity demand and supply for the 12-month supply period beginning each June (2015 was its third auction). The current MISO capacity market enables AESs to cover any capacity needs that have not been covered in the informal marketplace and yet are still needed to meet their short-term resource adequacy mandate.5

MISO's neighboring power system, PJM, began power restructuring in 1997 with a design incorporating both energy and capacity markets. PJM's initial capacity market design (known as the "capacity credit market") was similar to the current MISO capacity market design. However, five years of experience in PJM showed that normal fluctuations of demand and supply conditions from one year to the next produced a boom-and-bust pricing pattern. A similar pattern is emerging in MISO. In the most recent capacity auction, capacity prices in MISO Zone 4 moved up nearly ninefold from the prior year's auction price. PJM concluded that this approach did not fully address the inherent dimension of the missing money problem; it responded by evolving its formal capacity market into a formalforward capacity market that cleared projected

3. Jules Dupuit, "De la mesure de l'utilite des travaux publics,"' Annales des Ponts etChaussees, second series, VIII, 1844.

4. See the IHS Energy Multiclient Study Missing Money in Competitive Power Generator Cash .F1ows: Causes, consequences, and solutions, November 2014.

5. "First Annual Capacity Auction Cleared Under New RA Construct," MISO Energy, S April 2013.

© 2015 IHS 7 July 2015



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capacity demand and supply three years in advance with a payment commitment term of one to three years. In addition, PJM further limited the volatility of the capacity price by instituting a managed capacity demand curve and applying more stringent bidding rules to establish the capacity supply curve.

Experience with competitive power markets not only exposed the inherent missing money problem in energy markets but also indicated that even with a capacity market, very few wind and solar power generating technologies were likely to be built. However, growing concern over global warming led to the establishment of renewable portfolio standards that overrode this market outcome and imposed minimum power supply shares for renewable resources. The unintended consequence ofimposiug these power supplies into the generation mix was to depress the energy market-clearing price and aggravate the missing money problem. This suppression of market prices from renewable power mandates is the primary cause of the imposed dimension of the missing money problem.

The original plan for deregulation was to increase competitive forces by giving all retail consumers the ability to shop around and choose their power supplier-including a new set of AESs that would aggregate customer power needs and buy power from the marketplace on their behalf. On the supply side, deregulation involved two steps. The first step involved deregulating the generation business while preserving regulation in the transmission and distribution businesses. The second step was to continue to regulate the wires business while increasing competitive forces in power generation. Doing this required establishing a regional electric energy market with an independent system operator (ISO) to coordinate market interactions between buyers and sellers. The expectation was that this power industry structure would produce energy market-clearing prices sufficient to support timely and adequate investment to keep demand and supply in balance over the long run.

Michigan enacted its power deregulation plan into law 14 years ago with the passage of Public Acts (PAs) 141and142. From 2001 to 2008, PA 141 allowed retail open access. During this time, retail open access participation ranged from 3% to 20% ofutility load.6 On 1 April 2005, MISO began operating the regional electric energy marketplace.

Michigan's Public Service Commission (PSC) altered its deregulation plan by initiating its own study of the evolving power sector. PSC Chairman Peter Lark released the "Michigan's 21st Century Electric Energy Plan" in January 2007. The Michigan Legislature responded to the report's recommendations and changed the course of electricity industry restructuring with the passage of PAs 286 and 295 in 2008. This legislation made three major changes:

• Freezing retail open access. The plan to eventually have 100% of customers with retail open access was changed to limit it to just customers involved in iron ore mining and processing, along with 10% of the remaining average weathernormalized retail electric load. Traditional regulated utilities supply the remaining roughly 90% of power consumption in the state.

• Establishing utility integrated resource planning. The plan changed from relying on the marketplace for timely and adequate electric supply expansion in favor of an integrated resource planning process in which utilities detailed their expected demand and proposed supply actions, including PSC approval ofa Certificate of Need for new generating capacity before commencing construction.

• Mandating renewable power supply. This market intervention overrode the market result and imposed a minimum percentage of power supply from renewable power sources.

The changes Michigan made to its deregulation plan created the current hybrid power industry structure, and the changes to MISO market rules addressed some, but not all, of the missing money problem. These are the defining characteristics of the current Michigan power business landscape and the source of the problematic misalignments. These misalignments cause three power sector challenges in Michigan:

• Unfair power supply cost burdens (free riders). The missing money problem exists in the MISO power marketplace. Consequently, market cash flows from energy and capacity markets chronically fall short of covering the total cost of power supply. As a result, retail open access customers choosing suppliers that source capacity and energy from

6. "Rea dying Michigan to Make Good Energy Decisions: Electric Choice," Michigan PUblic Service Commission and Michigan Economic Development Corporation, 15 October 2013.

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the market typically pay Jess than full cost. In contrast, utility ratepayers cover total costs. Regulated utility charges fund utility investments in a diverse power supply portfolio that includes cycling and base-load power plants as well as renewables. This diverse generating portfolio produces a range of system wide benefits because these power supply resources participate in the energy market. The benefits they create-lower off-peak prices, cost risk management, and environmental controls-cannot be excluded from any buyers in the market. Thus, retail open access customers are free riders on the systemwide benefits paid for by utility ratepayers.

• A discriminatory option (to switch). Retail open access customers have the option to pay the lower of market or regulated power prices. Although the unresolved missing money problem means market prices for energy and capacity are chronically below average total costs, these market prices are far more volatile than regulated power prices. The MISO capacity market design produces a boom-and-bust pricing pattern, and the energy market reflects incremental cost-based power supply bids that are often Jinked to natural gas prices-the most volatile of power generation fuel costs. As a result, there is potential for energy and capacity price swings (particularly in a shortage period) to provide a valuable option to some customers to switch temporarily back to regulated power suppliers until the market price swings in reverse. As conditions reverse, customers can switch back again to AESs that source energy and capacity from the marketplace.

· Increased probability ofLower Peninsula power supply shortages (reliability challenges). Short-term demand and supply switching options hinder the Jong-term balancing of demand and supply to ensure reliable power supply. The flexibility ofretail open access customers to switch power suppliers in the short run makes it unclear who is responsible for planning for their capacity needs in the future. Further, short-term customer switching makes it difficult for suppliers to add capacity fast enough to meet the demand. Similarly, some power suppliers have the ability to switch power markets in the short run. The most recent example is the Covert power plant-one of the largest merchant power plants in Michigan-that is switching its (approximately) 1,000 megawatt (MW) power supply away from the MISO market and into the PJM market because PJM energy and capacity prices are expected to be higher. This 1,000 MW shift in power supply is under way, even though the most recent regional electric reliability survey indicates the need for more than 1,000 MW of capacity transfers from other MISO zones into MISO Zone 7 (Michigan Lower Peninsula) in 2016. These capacity transfers from other zones are needed to make up for the projected 1,200 to 1,300 MW shortfall in power supply to meet the expected MISO Zone 7 peak load in 2016. To put this shortfall in context, the expected Zone 7 capacity requirement for 2016 is 24.3 GW. The survey indicates that expected load growth will diminish the surplus capacity in MISO zones available to Zone 7 by 2019. Therefore, the survey concludes that additional actions are required in the near term to ensure sufficient power supply resources beyond 2019. 7

The opportunity to realign regulation and the market Misalignments in the current Michigan hybrid industry structure create three major problems: (1) an unfair distribution of power supply costs among consumers, (2) a switching option that discriminates in favor of some customers at the expense of other customers, and (3) an increase in the probability of electric reliability problems. The ramifications of these problems are

· Power costs distribution. The current Michigan hybrid power sector misalignments shift roughly $300 million per year of costs away from a minority of Michigan consumers (retail open access customers account for a little over 10% of the state's power consumption and approximately 0.5% of customers) to the majority of customers who are utility ratepayers. On average, two-thirds of the cost shift involves the fixed costs of power supply, and the remaining onethird reflects variable electric energy cost shifts. Since the systemwide benefits of utility investments are available to all customers, this allows a free ride to retail open access customers.

• Switching. This ongoing free rider problem is magnified by the option to switch suppliers. Although market prices for energy and capacity are currently below regulated prices, reflecting average total costs, sometimes the greater volatility of market prices creates conditions that reverse this relationship. As a result, although retail open access and utility ratepayers are both supplied from the same integrated power supply, retail open access customers have the option to

7. 2015 OMS (Organization ofMISO States] MISO Survey Results, July 2015.

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always pay the lower of AES or utility power prices. This option is discriminatory because it allows some customers to pay less at the expense of others.

Not surprisingly, customers recognize the value of a free ride and a discriminatory open access retail choice option. The waiting list for the retail open access program is twice as large as the number of customers allowed to participate under current regulations.

· System reliability. The probability ofunreliable power supply in Michigan's Lower Peninsula is increasing. The misalignment between short-run customer switching and long-run supply planning means that customer demands can shift back to regulated utility suppliers faster than utilities can site, permit, and construct required new capacity. This uncertainty regarding who is responsible for consumer demand in the long run is one reason why the current pipeline of new supply is less than the amount needed to keep up with demand increases and replace retiring generating resources. The margin for error in balancing power demand and supply is small. In Michigan, a reserve margin of 14.8% is required to reliably balance power demand and snpply. Dropping just 5 percentage points short of the target reserve margin substantially increases the probability of serious power system problems-emergency load shedding, brownouts, and price spikes altogether similar to what happened in California in 2000-01.

The implication is clear-the time has come for Michigan to realign its electric regulations with market realities. Based on !HS Energy research, Michigan has two options to realign regulations and the marketplace:

• Phase out partial retail open access. The most straightforward realignment option involves phasing out retail open access by mandating a shift back to utility supply.

• Alter partial retail open access-with two major revisions. This is a less definitive and more complex option. First, a surcharge needs to be added to the retail open access purchased power charges to address the free rider problem and level the burden across all customers of recovering utility investments in systemwide efficiency, risk management, and environmental benefits. Second, a rule needs to be put in place requiring AESs to demonstrate a firm forward supply arrangement for the projected needs of their current customers to provide enough lead time (at least five to seven years) to develop not only peaking units but also the cycling and base-load power plants necessary for efficient and reliable power supply.

Conclusion

All too often, it takes a crisis to force changes in the power industry structure. In the case of the California power crisis, the evidence that underinvestment was preventing power supply from keeping up with demand was apparent, but actions did not materialize until after a severe shortage unfolded. More recently, the problems of coordinating natural gas and power supply infrastructure simmered for years on a back burner until the polar vortex in the 2013/14 winter forced power systems to reevaluate how they defined and paid for firm power supply.

Michigan has misalignments in its current hybrid power industry structure that create problems-uneven and unfair cost burdens, a discriminatory switching option, and the increasing probability for insufficient power system reliability. But rather than wait for these problems to produce a crisis, Michigan can move forward and ensure that its power system remains reliable, efficient, and environmentally compliant. Corrective actions will enable a fair distribution of costs to customer classes and maintain the competitiveness of electric input costs to Michigan businesses.

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Michigan's electric power industry structure: An unplanned hybrid Power industry restructuring did not play out as planned. US power industry restructuring began in the 1990s. At that time, the traditional power industry structure involved the regulation of franchised power companies providing generation, transmission, distribution, and customer billing services. Prior to deregulation, the traditional industry structure produced significant differences in power prices from one utility to the next. The enthusiasm to move away from traditional regulation and rely more on market forces reflected the hope that the introduction of more competitive forces would drive out these cost differences, encourage innovation, and lower power bills. Most restructuring plans reflected a simple faith thatthe marketplace would produce a textbook result where market-clearing prices for electric energy would signal timely investment and support adequate power supply development.

In Michigan, the traditional regulated industry structure involved two regulated utilities: Consumers Energy (CMS) and Detroit Edison (DTE) supplied the capacity, generation, transmission, distribution, and customer interface for approximately 90% of Michigan electric consumer electricity consumption. The regulated rates charged to consumers reflected the average total costs of power supply allocated to different classes of customers based on cost responsibility.

Pressures to reduce power price differences between utilities were much greater in some places compared to others. As a result, there was no standard path or pace to restructuring the power sector. Some states made minor changes, while other states substantially increased the role of market forces on both the consumer (retail) and producer (wholesale) sides of the power business. Michigan was among the 17 states (California, Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, Montana, New Hampshire, New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island, and Texas) plus the District of Columbia that expanded their reliance on market forces to some degree on both the wholesale and retail sides of the power business.

Michigan's electric restructuring plan went further than most state plans in setting goals and timetables to move from regulation to deregulation. The original plan for deregulation was to give all retail consumers the ability to shop around and choose their power supplier-including a new set of AESs that would aggregate customer power needs and buy power from the marketplace on their behalf. The goal was to increase competitive forces by unleashing retail customers to shop around for the best deal. On the supply side, the plan was to unbundle utilities-separating the generation business from the transmission and distribution businesses. The idea was to continue to regulate the wires side of the business and increase competitive forces by instituting competitive bidding for power supply among rival generators, with a regulated power grid operated by an ISO providing the coordination to enable market interactions between buyers and sellers. The expectation was that this power industry structure would produce energy market-clearing prices sufficient to support timely and adequate investment to keep demand and supply in balance over the long run.

Michigan enacted its power deregulation plan into law 14 years ago with the passage of PAs 141and142. From 2001 to 2008, PA 141 allowed retail open access (2000PA141). During this time, retail open access participation ranged from 3% to 20% of utility load.' However, as Michigan began implementing its power restructuring plan, the problematic realities of power industry restructuring efforts elsewhere were coming to light. In particular, the gap between deregulation expectations and the reality became increasingly apparent in California, where the restructuring process had begun about seven years ahead of Michigan.

Both the initial California and MISO market designs involved only an electric energy market. When California began operating its energy marketplace in 1998, the power system had a surplus of generating capacity. As expected with surplus supply conditions, market operations produced market-clearing prices for electric energy that were too low to provide the cash flows necessary to support new power supply investment. But as time passed, an unexpected result began to emerge. The low wholesale power prices persisted even when load growth resolved surplus supply and brought demand and supply into balance with the desired reserve margin. This California electric energy market result was at odds with the economics textbook model of a competitive marketplace. As the California economy expanded and power demand increased further, wholesale energy prices remained below the average total cost of new supply.

8. "Readying Michigan-to Make Good Energy Decisions: Electric Choice," Michigan Public Service Commission and Michigan Economic Development Corporation, 15 October 2013.

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The chronically low prices produced by an energy-only market design in California caused underinvestment in power supply. Consequently, the continued reserve margin decline brought supply below the level needed to maintain reliability and increased the probability of power reliability problems. Figure 1 shows the declining supply reserve and the increasing frequency of shortage-driven stage 1-3 emergency procedures. Figure 1

The inevitable consequence was a severe power shortage with dramatic wholesale power price spikes and rolling blackouts. Making matters worse, some power traders attempted to profit by taking advantage of shortage conditions.

The problem of chronically low market power prices was not unique to California. Most electric energy markets produced market-clearing power prices that were consistently below the average total cost of power supply. These conditions caused "mercl1ant" generators-power suppliers that primarily rely on market cash flows to recover costs-to write down assets, sell power plants at substantial discounts to cost, and in many cases undergo bankruptcy

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reorganizations. About 5 GW of Michigan's total 30 GW of power supply was originally built by merchant generators. Since deregulation began, the three merchant generating companies owning approximately 75% of this supply have gone through bankruptcy: National Energy and Gas Transmission (a unit of PG&E) and Mirant in 2003, and Dynegy in 2011. Financial distress forced the sale ofa majority of these power plants at a significant discount to the net cost. Half of the generating capacity originally built by merchant generating companies in Michigan is now owned by regulated utilities. In the past decade, merchant generators have not built any conventional generating power plants in Michigan.

Despite low wholesale prices for merchant generators, consumer power bills went up rather than down in the era of deregulation owing to the costs imposed by market interventions to avert a California style crisis and to scale up wind and solar power generation. The accumulating evidence drove industry observers to agree that power industry restructuring was not working as planned (see the box "Reassessing power industry restructuring").

A consensus did not quickly form regarding what had gone wrong in the California power deregulation process because the underlying market flaw remained obscure. As a result, it was not clear what needed to be done to move forward and avoid similar problems in other efforts to implement deregulation. Following the California power crisis, seven statesArizona, Arkansas, California, Nevada, New Mexico, Virginia, and Wyoming-passed legislation to suspend power restructuring efforts. Consequently, industry restructuring lost momentum, and most electricity restructuring efforts stalled.

Inherent and imposed power market flaws produce a missing money problem The root causes of the failures in implementing power deregulation are a complex mix of inherent market flaws and unintended consequences from regulations imposed on power supply.

A focus on markets that fail to produce textbook market results because an inherent characteristic of the supply technology is neither new nor unique to the power business. A nineteenth-century French engineer and economist, Jules Dupuit, analyzed the investment problem in the railroad industry resulting from the gap between fixed and variable

© 2015 IHS 12 July 2015



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!HS Energy I Meeting the Michigan Power Sector Challenge

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costs.9 Dupuit communicated the root cause of the problem by developing the example of a bridge-a technology with a large up-front capital cost, a positive average total cost but a zero marginal cost for bridge crossings.10 He argued that competitive forces would logically drive the market price to zero and underinvestment would lead to market failure.

The power business is another exception to the general market rule. The underlying inherent flaw in power deregulation is that the technologies employed to cost-effectively generate electricity do not have the characteristics needed to produce a textbook market outcome in which prices l<eep demand and supply in long-run balance. Contemporary economists call this the missing money problem.11

The missing money problem prevents the normal corrective forces of the textbook marketplace from moving the power market into a long-run demand and supply balance. In an economics textbook, the industry marketplace employs production technologies that generate corrective forces when market conditions are out oflong-run balance. In particular, when prices are below average total costs, suppliers will not invest capital in new productive capacity. However, a lack of new investment in productive capacity does not mean supply will cease. Existing demand is met because market-clearing prices can settle below average total costs but above the variable production costs. Under these conditions, suppliers produce output and generate cash flows that provide some contribution to the capital already deployed in manufacturing capacity. Nevertheless, as capital wears out and is not replaced and/or as consumer demand increases, balancing demand and supply requires the market-clearing price to rise enough to cover the higher

9. Jules Dupuit, "De l'Influence des Peages sur l'Utilite des Voles de Con1munication,'' Anna/es des Pon ts etChaussfrs, no. 207, 1849, p. 170-248.

10. Jules Dupuit, "De la mesure de l'utilite des travaux publics" Ann ales des Ponts et Chausse es, second series, VIII, 1844.

11. The tenn missing money was first used to describe fixed-cost recovery in power by Peter Cram ton and Steven St oft in their 2006 paper, "The Convergence ofMarket Designs for Adequate Generating Capacity," written for the California Independent System Operator's Electricity Oversight Board.

© 2015 IHS 13 July 2015



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incremental costs associated with producing more and more output without expanding capacity-a marginal cost characteristic of technologies that reflect the law of diminishing marginal returns. Eventually, the incremental costs of expanding output without expanding capacity reach the level of average total costs. At this point, market-clearing prices are high enough to support deploying new capital to expand capacity, and there is a lower cost to expand output with new capacity than to expand output by employing just more variable inputs. This end state is the textbook case of corrective market forces that willmove the market to a Jong-run competitive equilibrium.

The inherent flaw in electric energy markets is that power generation technologies can alter output with fixed capacity by adjusting variable inputs such as fuel; but the impact of the law of diminishing marginal returns is not strong enough to close the gap between incremental generating costs and average total costs before the capacity reaches its utilization limit. But power plants do not run at their maximum utilization rate when demand and supply are in balance because customers do not need the same amount of power at all times. The average hourly demand for power is typically about 60% of the maximum hourly demand (the ratio of average load to peak load is the power system load factor). In a power system with a reserve margin adequate to ensure reliability, the average utilization rate ofinstalled generating capacity is a little Jess than the system load factor.

As a result, when power demand and supply are in balance-including the desired reserve margin of productive capacity-the average utilization rate of a power plant approaches the system load factor, and the incremental cost-based market-clearing price remains significantly below average total costs.

Figure 2 illustrates the inherent problem with power generation technology cost profiles. A tightening demand and supply balance causes higher power plant utilization; but although the gap between incremental costs and average total costs narrows, it does not close Figure 2

as average utilization increases and approaches the system load factor. As a result, this characteristic of power supply technologies means a chronic shortfall between incremental costbased market-clearing energy prices and average total costs-a predictable outcome in a competitive energy marketplace.

The inherent missing money problem for power generating technologies is magnified when market interventions impose additional supply into the marketplace and lower the marketclearing price. For example, imposing mandates for renewable power generation increases the supply of technologies with a zero marginal cost. Adding these resources to the electric energy market supply curve Jowers

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the market-clearing electric energy price. This price suppression is magnified by the subsidies available for each unit of wind electric output. Under these conditions, rival renewable generators find that they can bid negative prices as long as the subsidies they earn are more than enough to cover the cost of paying buyers to take their power. As a result, when subsidized wind resources bid against each other to clear an energy marketplace, the price can be driven to a negative level.

Altering power deregulation plans The economic impact of the California power crisis of2000-01 was so severe that it altered power industry restructuring plans not only in California but around the world. California made structural adjustments after recognizing that

© 2015 IHS 14 July 2015



Page 25 of 43


prosecuting law-breaking power traders and trying to recover the ill-gotten gains of the power crisis did not address the root cause of the shortages. After using an ad hoc approach of power plant contracts following the crisis, California instituted a resource adequacy rule in 2004 that became binding in 2006. This new rule required all load-serving entities to have enough capacity to meet their customers' aggregate demand plus a minimum reserve margin. The rule created a demand for capacity and enabled an informal capacity market to arise. An informal marketplace does not organize market interactions but rather relies on capacity buyers and sellers to seek each other out for transactions. The resulting contract prices, terms, and conditions were typically known only to the contract counterparties, however, and thus the informal market provided little capacity price transparency.

Michigan's PSC began altering its deregulation plan by initiating its own study of the evolving power sector. PSC Chairman Peter Lark released the "Michigan's 21st Century Electric Energy Plan" in January 2007. The Michigan Legislature responded to the report's recommendations and altered the course of electricity industry restructuring with the passage of PAs 286 and 295 in 2008. This legislation made three major changes:

• Freeze retail open access. The plan to eventually have 100% of customers with retail open access was changed to limit it to just customers involved in iron ore mining and processing, along with 10% of the remaining average weathernormalized retail electric load .

• Establish utility integrated resource planning. The plan to rely on the marketplace for timely and adequate electric supply expansion was changed in favor of an integrated resource planning process in which utilities detailed their expected demand and proposed snpply actions, including PSC approval of a Certificate of Need for new generating capacity, before commencing constrnction .

• Mandate renewable power supply. This market intervention overrode the market resnlt and imposed a minimum percentage of power snpply from renewable power sources.

Market institutions-IS Os and regional transmission organizations-evolved rules governing power marketplaces to address the reliability challenges cansed by the missing money problem. However, the regional market structural adjustments were quite varied. Three structural adjustments to the power industry relevant to Michigan included

• MISO resource adequacy requirement

• MISO formal capacity market

• PJM formal forward capacity market

MISO followed other power systems in addressing the missing money problem by evolving beyond its initial plan for an energy-only market design. From the start, the MISO energy market consistently delivered an efficient utilization of available electric capacity in the short run by clearing the market with prices that reflect the incremental variable costs of generation. As a result, the level and volatility ofMISO energy prices typically covered the fuel and variable operating and maintenance costs of generating plants and provided some contribution to fixed costs. Yet after operating with an energy-only market design for a decade, MISO altered its rules to include a resource adequacy mandate in 2009. The resource adequacy mandate created an informal capacity market in MISO.

Four years after mandating a resource adequacy rule, MISO enhanced the mandate by implementing a formal capacity market to clear demand and supply about two months in advance of the annual peak demand. With the enhanced resource adequacy approach, MISO runs a voluntary capacity auction each April to balance capacity demand and supply for the 12-month supply period beginning each June (2015 was its third auction). This formal market enables AESs to cover any capacity needs that have not been covered in the informal marketplace and yet are still needed to meet their resource adequacy mandate." In addition, the formal MISO marketplace increased capacity price transparency.

Unlike California and MISO, PJM began power restructuring with both energy and capacity marketplaces. However, after five years of experience with its formal capacity market, known as the capacity credit market, PJM found that

11. ''First Annual Capacity Auction Cleared Under New RA Construct," MISO Energy, 5 April 1013.

© 2015 IHS 15 July 2015



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this market design produced a boom-and-bust capacity price pattern and concluded that the power supply investment price signal could be improved by reducing the market's volatility. PJM responded by evolving its formal capacity market into a formal forward capacity market that cleared projected capacity demand and supply three years in advance with a payment commitment term of one to three years. In addition, the volatility of the capacity price was further limited by instituting a managed capacity demand curve and applying more stringent bidding rules to establish the capacity supply curve.

Regulated utility rates include full power supply cost recovery The shortcomings of power deregulation to produce power prices high enough to fully cover costs created a renewed appreciation for regulated utilities whose retail rates reflected the total costs of power supply. These regulated rates covered the costs of reliably providing consumers with the electricity that they need, when they need it. To do this requires covering the costs to build and operate an efficient, diverse, and environmentally compliant generation portfolio that includes peaking, cycling, and base-load power plants along with demand-side resources and renewable resources.

Managing the ups and downs of electric energy use through time with storage technologies is more expensive than having enough capacity installed to meet needs at any point in time. Thus, planning for reliable power supply at all times focuses on the stock (megawatts) of productive capacity rather than flow of electric energy (megawatt-hours). Reliability requires sufficient available capacity to meet instantaneous power demand. A simple-cycle combustion turbine technology typically provides the lowest-cost pure capacity to meet aggregate consumer power demands. Although these peaking technologies are not the most efficient technologies in transforming fuel into electric energy, they are nevertheless the lowest up-front cost option to have a megawatt of capacity in place to meet power demands.

Since power reliability simply involves having adequate capacity, peaking technologies set the cost benchmark. The benchmark average annual levelized cost of the peaking technology is known as the "cost of new entry" (CONE). The CONE is adjusted whenever expected energy market and ancillary services cash flows can offset some of the up-front costs. This adjusted cost benchmark, known as '.'net CONE," reflects the value of"pure capacity" or in other words, the cost of reliability.

Although a utility finds that the lowest cost of pure capacity involves building a peaking unit, the utility does not build a power supply portfolio made up entirely by peaking technologies. Instead, a utility invests in a broad range of generation technologies making up a power supply portfolio designed to perform well in the long run. Some of the power supply technologies in this mix have capacity costs in excess of the combustion turbine-for example a natural gas-fired combined-cycle power plant that is more efficient at transforming natural gas into electric energy. In this case, the investment makes economic sense because the expected value of the fuel savings is more than enough to pay for the higher up-front capacity costs. The implication is that some of the additional capacity costs in a power supply portfolio that are over and above those of a combustion turbine are a cost-effective investment in fuel efficiency.

Some additional power plant investment provides production cost risk management. The cost of generating electricity is inherently uncertain. Oil, natural gas, coal, and uranium prices are difficult to predict and are prone to multiyear price cycles, short-term price volatility, and deliverability constraints. Alternative power generation technologies also rely on fuels with uncertain future prices and, in addition, have different performance risks. For example, hydroelectric power plants are limited by drought, whereas combustion turbine risks include, for instance, natural gas pipeline constraints on fuel deliverability.

Since technology performance characteristics and fuel price movements are not highly correlated, a diverse portfolio of fuels and technologies provides the most cost-effective way to manage the cost risk of power production. As a result, the additional cost of capacity over and above the combustion turbine reflects investment both in fuel efficiency and in risk management of power supply costs. Risk management investments are essential to reduce overall power supply costsmore stable costs create more stable cash flows. More stable cash flows reduce the size and thus cost of working capital and also lower the risk premium in the cost of capital.

Finally, some investments in power plants produce a cleaner environment. Utilities must try to balance environmental costs and benefits. To do this, some investments internalize the cost of pollution control technologies. Some of the

© 2015 IHS 16 July 2015



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higher variable costs of operation associated with pollution control are reflected in the incremental costs that set wholesale power prices some of the time. However, most of the environmental control costs are capitalized costs, and they are not covered by the capacity market cash flows that only cover the net CONE.

Evolving market designs still produce power supply cost recovery shortfalls Cash flows from MISO energy and capacity markets addressed some, but not all, of the missing money problem. As a result, market cash flows continue to fall short of covering the total costs associated with an economically efficient and environmentally compliant generation portfolio.

MISO's enhanced resource adequacy construct created its capacity market. Resource adequacy means having enough capacity to reliably meet aggregate consumer demands. From a reliability perspective, market cash flows need to cover only the up-front cost of producing the lowest-cost source of capacity. Therefore, a metric to evaluate the MISO capacity market is the relationship of the capacity price to the net CONE.

Currently, the MISO Zone 7 net CONE is $65.10 per kilowatt per year (kW-year), and the CONE is $90.10/kW-year.13 The difference between the MISO CONE and net CONE shows that even for a peaking power plant with an expected low utilization rate, the contribution from energy market cash flows accounts for about one-third of annual carrying charges of the up-front investment costs.

An investment proforma for cycling and base-load units needs a higher percentage of annual up-front carrying costs to be covered by energy market contributions compared with a peaking unit. Therefore, a well-functioning energy market is essential to providing the energy margins needed to cover the additional up-front costs of cycling or base-load power plants that produce electric energy (megawatt-hours through time) more efficiently, more cleanly, or with less risk than the peaking unit.

Capacity market cash flow supplements energy market cash flow. In MISO, the capacity market cash flow only partially addresses the inherent technology-based dimension of the missing money problem, and it does not address the imposed renewable policy dimension of the problem. Policy interventions into the MISO energy market depress energy market cash flows, which then fall short of covering the additional costs ofbuilding a power generation portfolio with a costeffective mix of peaking, cycling, and base-load power plants. On the revenue side, mandates for renewable power and subsidies based on renewable output depress wholesale prices and reduce power plant utilization rates. On the cost side of the energy cash flow, the renewable power mandates cause cycling power plants to start up, ramp up and down, and shut down more frequently to back up and fill in for the intermittent pattern of renewable power generation. The combined effect is to depress energy market revenues and increase variable operating costs for nonpeaking power plants. As a result, the market interventions impose missing money shortfalls in market cash flows and cause an underrecovery of the cycling and base-load costs in an efficient generation supply portfolio.

An uneven playing field for retail open access competition Retail open access sets up competition on an uneven playing field between regulated and unregulated power suppliers. Unregulated suppliers can source energy and capacity from the marketplace at prices that are chronically below the average total power supply cost owing to the unresolved dimensions of the missing money problem. In contrast, regulated utilities' prices reflect average total power system costs.

CMS and DTE are regulated utilities that serve more than 80% ofMichigan's electric consumption. Regulated rates cover the average cost of all of the components needed to deliver cost-effective power supply. Figure 3 provides a breakdown of the components of the current regulated power rates for consumers by customer class in Michigan. In particular, the generation cost component ofregulated retail power rates can be separated into variable production costs and the remaining capacity costs.

13. Gross CONE is cited in the MISO Locational Resource Zone Cost of New Entry filing to the Federal Energy Regulatory Commission (FERC), 3 September 2013. The $25.00/kW-year net revenue for a combustion turbine due to sales of energy and ancillary services is approximated from Figure 6 of the 2013 State of the Market Report for the MISO Electricity Markets, Potomac Economics, June 2014.

© 2015 IHS 17 July 2015



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Figure 3 Michigan regulated retail rates incorporate a variable cost component designed to cover average variable production costs. This component includes the cost of power purchased from the market as well as variable costs that are not included in the incremental costs that underpin market-clearing energy prices. For example, regulated variable charges usually cover power plant labor costs, whereas incremental cost for power production typically does not because power plant employment levels generally do not vary with short-

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run changes in power plant output. Therefore, a competitive bidder will bid to generate whenever the price is above incremental costs and thus make some contribution to fixed costs, including labor costs.

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In 2013, the average regulated energy price in Michigan was 4.49 cents/kWh compared with the MISO Zone 7 average wholesale price of electric energy of3.38 cents/kWh. 14

In the regulated price, the component covering the average cost of capacity ranges from 3 to 4 cents/kWh across different customer classes. This nonvariable generating cost reflects the average historical embedded cost of capacity in the utility generation portfolio. Using the ratio of peak demand to average demand allows conversion of this cents-per-kilowatthour charge to a dollar-per-kilowatt-per-year charge. The conversion yields a charge of about $200/kW-year representing the embedded cost of capacity in regulatedrates.15 Roughly one-third of the regulated embedded capacity charge covers the investments made to provide reliability (net CONE). The remaining two-thirds covers the cost to provide production

· efficiencies through a mix of peaking, cycling, and base-load resources; risk mitigation through a diverse fuel and operating technology mix; and compliance with existing environmental regulations through environmental control investments.

The market-clearing MISO Zone 7 capacity price for the summer of2015 was $1.27/kW-year. This price is lower than the $6.10/kW-year market-clearing MISO Zone 7 capacity price for the summer of 2014. To put these prices into perspective, the capacity price needs to be around $65.10/kW-year to provide the cash flow necessary to cover the net CONE. Therefore, experience to date shows MISO Zone 7 capacity prices are less than 10% of the net CONE benchmark and indicate that market prices are currently in the bust phase of a capacity price cycle.

Figure 4 compares the cost coverage of the current capacity costs embedded in Michigan regulated rates to the cost coverage of the recent market-clearing MISO capacity price. Since MISO capacity prices were in the bust phase in 2014, this price level enabled retail open access customers to pay an estimated $290 million less for the various benefits of Michigan's installed capacity portfolio compared with utility ratepayers.

The MISO capacity and energy market designs produce market-based cash flows that do not fully cover power supply costs, whereas regulated rates cover the total costs of power supply. Yet the same power system produces electric supply for retail open access customers as well as utility ratepayers; the level of reliability, sources of energy, and environmental impact of the power supply are the same for all consumers. Despite this common source, customers choosing suppliers that source capacity and energy from the market pay less than utility ratepayers that cover the entire cost of producing

14. Regulated cost of energy based on weighted-average cost of energy from rate cases DTE (U-17767) and CMS (U-1 7735); MISO Zone 7 price is the Michigan Hub average day-ahead wholesale price.

15. Based on weighted-average load factors and costs of capacity from DTE rate schedules.

© 2015 IHS 18 July 2015



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Figure 4 electricity with a cost-effective, environmentally compliant generation portfolio. The uneven playing field for AESs and utilities creates an unfair cost distribution between consumers served by AESs sourcing power system outputs at market prices and regulated utilities providing power on an average cost basis.

MISC> .Ci'.Paci~ price

Systemwide benefit for free riders Michigan's free rider problem accounts for an annual average cost shift of nearly $300 million to utility ratepayers and away from retail open access customers being served by AESs sourcing market-based capacity and energy. On average, two-thirds of the cost shift involves the fixed costs of

Reliability/capacity cost

• Costs covered

Source: Ii-IS Enargy

power supply, and one-third involves variable costs.

• t:m Costs not covered

© 2015 IHS: 50505-1

Michigan utility ratepayers create overall system benefits by funding investments in production efficiency, risk management, and environmental impact mitigation. These benefits spill over to the marketplace and produce cleaner, more cost-effective, and less volatile market-clearing power prices because regulated utility-owned power plants compete in the MISO wholesale energy market. Retail open access customers are free riders because these systemwide benefits are inherent in delivering power.

The benefit of cost risk management is significant. For example, the diverse Michigan power supply portfolio produces incremental generating costs that are lower and less volatile than an all natural gas-fired generation portfolio. Figure 5 shows that if Michigan power supply lacked fuel and technology diversity and relied on only natural gas-fired combustion turbines for power supply, then the wholesale price of power in the state of Michigan from 2010 to 2013 would have been over 50% higher, and the monthly price variation would have been over three times greater than the actual level and variations in market-clearing prices. Here again, consumers paying market-based power prices for energy are free riders that benefit from, but do not pay for, the investments made to diversify the fuel and technology mix.

Demand-side management programs also produce systemwide benefits. The impact of the accumulated investment

© 2015 IHS

Figure 5

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Page 30 of 43


in these programs reduces aggregate consumer demand for capacity and thus reduces and delays increases in the marketclearing price of capacity.

Market prices for energy and capacity vary more than regulated prices Market prices and regulated costs differ in variability as well as levels. Both characteristics create an uneven playing field for retail open access. The combination of the boom-and-bust market capacity prices pattern plus the wholesale energy price pattern makes the market costs of power (the sum of market capacity and energy prices) significantly more variable through time compared to the regulated costs of power. Regulated power prices incorporate capacity costs that reflect the embedded cost of service. This approach produces more stable capacity costs than the expected capacity prices under the current MISO capacity market design.

Boom-and-bust capacity price patterns are a predictable result of the MISO formal capacity market design incorporating inelastic demand and supply curves. Demand and supply conditions vary enough from one year to the next that it is unlikely that market demand and supply curves will line up and allow MISO Zone 7 prices to consistently clear at the average total cost of new supply. Instead, demand and supply fluctuations will produce a boom-and-bust price pattern.

The MISO capacity demand and supply curves are price inelastic. In the short run, MISO power demand will not change much in just a few months in response to a change in the capacity price. This short lead time does not allow enough time for demand to respond to price signals, so demand is price inelastic. Similarly, the supply curve is also price inelastic because the formal capacity market clears less than two months ahead of the supply period, and such a short lead time does not allow enough time for new supply build to enter the market in response to these price signals and change the demand and supply balance.

A market with price-inelastic demand and supply curves tends to produce volatile prices around average total costs when demand and supply are close to balance. The Appendix describes why normal variations in demand and supply fundamentals will generate boom-and-bust pricing patterns when the market demand and supply curves are both price inelastic.

With only three years ofMISO market-clearing prices, it is not clear where the average price will settle, on average, over the long run. However, if the MISO formal capacity market price were going to cover the average total cost of new capacity over the life of the power plant, then the boom prices have to be high enough over a long enough period of time to make up for the intervals ofbust price levels. Looking ahead, the expected increase in demand and decline in supply are likely to produce boom prices around 2020. If recent prices are an indicator ofbust price levels, then bust prices will typically be around 10% ofnet CONE. In contrast, boom prices are limited by the MISO capacity price cap. With these price levels, boom prices would need to prevail roughly 70% of the time to offset the impact ofbust prices during the other 30% of the time. However, since the MISO capacity market outcomes are simply too few to provide a useful sample to assess the expected long-run average price result, and the observations of similar capacity market designs were also too limited, it is not possible to conclude that this capacity market design will produce a price that averaged to net CONE over the life of a generating asset.

The expectation that the MISO capacity market design will produce boom-and-bust prices is not just theoretical. Other power markets provide price experience with similar capacity market designs. In particular, PJM employed a formal capacity market design from 2000 to 2004 that is similar to MISO's. As Figure 6 shows, this capacity market design produced boom-and-bust patterns for capacity prices that did not average to net CONE over an extended period of time.

An additional source of volatility in the cost of electricity sourced from the marketplace comes from the varying price of energy, as measured by prices in the wholesale market. MISO's price of energy varies more than the regulated variable charge of energy. Figure 7 shows market prices that reflect the incremental fuel costs ofrival fuel generators. Natural gas-fired power plants are often the marginal generators with bids that set the market-clearing price. In MISO North (MISO excluding Entergy), natural gas-fired power plants constitute 27% of installed capacity and are on the margin, setting prices about 29% of the time. As Figure 7 shows, natural gas prices are the most cyclical and volatile of the fuel sources used to generate electricity.

© 2015 IHS 20 July 2015

- ---------- ·······"~·-·--·-----------



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The natural gas price variation is a primary driver of the wholesale energy price variation. Figure 8 shows the monthly MISO Michigan Hub wholesale energy price variation. These market energy prices were three times more varied than the regulated Michigan monthly average variable cost of power production.16

Slight changes in the factors that influence consumer demand and installed capacity levels drive the boom-and-bust price patterns in the MISO capacity market. A different set of factors drives the ups and downs of natural gas prices and thus the wholesale price of energy. Although atypical, the potential exists for a coincident run-up of market prices for both energy and capacity. These various situations create a valuable option for customers that can always switch to buy the lowerofregulated or market-based power supply prices for energy and capacity. For example, for several years during the previous decade, market wholesale power rates exceeded regulated rates, and retail open access participation dropped nearly to zero.

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A discriminatory retail open access optionconfirmed by consumer actions 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

The unintended consequence of the retail open access level ofl0% of power demand is the creation of a valuable option for some customers but not

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others. Consumers with that option can switch to avoid paying their share of capacity costs by timing their switching activity between AESs and regulated utilities. Retail open access consumers will select an AES that sources supply from the capacity marketplace when the provider is passing through a capacity price well below the regulated price (bust periods). When the AES price incorporates boom market capacity prices that are well above the regulated capacity price, these customers will switch back to the regulated utility. Well-timed switching allows these customers to avoid paying their share of the full costs of power capacity, in particular because of the relatively short notice required to switch suppliers, making it easier to time switching to benefit from pricing differences.

16. Comparison based on the statistical measure of the "coefficient of variation" defined as the standard deviation divided by the mean.

© 2015 JHS 21 July 2015



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JHS Energy I Meeting the Michigan Power Sector Challenge

The value of the free ride and discriminatory option provided by limited retail open access has not gone unnoticed. Not surprisingly, the waiting list for the retail open access program is twice as large as the current participation limits. 17 As ofJanuary 2015, close to 11,000 utility customers were in the queue to acquire these advantages through the existing retail open access program.

Looking ahead, the program providing this valuable free option will likely remain oversubscribed. There is some potential for dramatic swings when market capacity prices boom and natural gas prices spike, driving customers to opt out. Yet they will likely quickly return when the capacity market cycles back to a bust pricing phase and customers swing away from

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regulated supply. Note that most of the current retail open access customers are nonresidential consumers with more than 1 MW of demand, so·the current misalignment disproportionately shifts the cost burden onto, and discriminates against, residential consumers.

Short-run switching options hinder balancing demand and supply in the long run Retail open access customers' ability to switch suppliers in the short run creates uncertainty over power supply responsibilities and long-run planning. Competitive forces drive AESs to satisfy some of their needs from the short-run capacity market. When uncertain market conditions shift.from bust to boom, regulated power costs improve relative to market-sourced power supply. In addition, the energy market price can also run up owing to cyclical fluctuations of the delivered price of marginal generation fuels-especially natural gas. A combination of booming capacity prices and high incremental generating fuel prices creates conditions that force market-sonrcing power suppliers to try to pass these costs on to customers; but these customers will then have a strong economic incentive to switch back to a regulated power provider and pay the temporarily lower electricity rates reflecting the average embedded historical capacity cost and average variable costs. The problem is that the timing of such relative price reversals is hard to predict, and market conditions can turn quickly. Therefore regulated suppliers are unlikely to have the certainty or lead time to respond. The probability that utilities will be put in this position is increasing as MISO capacity prices are poised to move out of the bust phase around 2020.

Utilities ensure reliability by projecting power demand and supply years in advance. Supply development involves multiyear lead times to plan, site, permit, and construct new resources that, once built, typically operate for decades. Consequently, prudent planning requires reliability assessments covering many years ahead. The objective of power supply planning is to ensure enough installed electric generating capacity in place to meet expected aggregate consumer demands plus a reserve margin to protect against the impact of adverse conditions, such as extreme weather, greaterthan-normal power plant outages, low output from intermittent resources (e.g., wind power), and demand forecast error.

In Michigan, the target planning reserve margin is 14.8%, reflecting the reliability standards set by ReliabilityFirst, the organization responsible for the regional electric reliability planning that includes Michigan. ReliabilityFirst is part of the North American Electric Reliability Corporation, which implements federal mandates for electric reliability under

17. According to the 2014 "Status of Electric Competition in Michigan" report released by the Michigan PSC, there are 6,460 customers enrolled in retail open access and approximately 11,000 in the queue.

© 2015 IHS 22 July 2015



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the regulatory oversight ofFERC. ReliabilityFirst is also responsible for imposing penalties for violations ofits reliability standards.

Demand and supply trends brought Michigan's power system into long-run balance close to a decade ago. In 2006, the Michigan PSC projected an electric demand and supply balance in the near future but an insufficient pipeline of new supply under development for subsequent years. The Michigan Capacity Needs Forum: Staff Report to Michigan Public Service Commission concluded in January 2006

Unless there are some significant enhancements to existing supplies, growing demand will cause existing electric generation and transmission capacity to be insufficient to maintain reliability standards in the Lower Peninsula.

Shortly after the PSC reliability assessment, the business cycle produced an unanticipated temporary reprieve from the impending power supply shortfall in the Lower Peninsula. At the end of2007, the most severe economic downturn since the Great Depression began. Reduced business activity and lower household purchasing power reduced power demand. The economic downturn dropped Michigan peak power demand by over 3,000 MW (December 2007 to June 2009). Michigan economic data indicate that the economic downturn hit the state sooner and the economic upswing took hold later than the overall US economic cycle. Nevertheless, as the US economic recovery gained traction, so too have the Michigan economy and electric power demand recovered.

The temporary impact of the business cycle on long-run electricity consumption trends is nothing new. The previous US economic recession (March to November 2001) reduced power demand, and then the subsequent economic expansion increased power demand faster than the underlying trend from 2002 to 2007. As the economy pushed electric demand upward, variations from normal weather conditions moved annual power demand up or down by as much as 1,000 MW. Figure 9 shows the combination of atypical weather impacts and business cyclical impacts on Michigan Zone 7 power demand through time.

A prudent plan to balance power demand and supply in the long run does not try to pace supply development with the short-run influences of the business cycle. Predicting the timing ofbusiness cycles is so uncertain that it is prudent to plan to have enough electric generating capacity to meet power demands when the economy is operating at full employment, even though an economic downturn can depress power demand for several years compared with the expected power use with normal economic activity. In 2006, prudent electric supply planning could not delay the development of new resources by betting on lower power demand because of an upcoming multiyear economic downturn.

Looking ahead, the economic recovery that began in mid-2009

Figure 9

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continues to push Michigan electric use higher. But on the supply side, current Michigan Zone 7 trends are moving in a negative direction. In particular, the pace of power plant retirements is accelerating and outpacing capacity additions owing to a confluence of factors including conventional air pollution regulations and structurally lower natural gas prices. Additional power plant retirements are expected given the uncertainty around the proposed US Environmental Protection Agency regulations to reduce greenhouse gas emissions from existing power plants. In addition, the wholesale

© 2015 IHS 23 July 2015



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electric energy and capacity prices are still below the level needed to support power supply development by nonregulated suppliers and are not triggering enough overall new power plant development. Instead, wholesale capacity and energy prices are triggering additional power plant retirements.

Tightening environmental regulations are accelerating the rate of power plant retirements. Current trends indicate that MISO Zone 7 will have a net loss of 612 MW of electric generating capacity by 2016. Scheduled retirements of coal-fired electric generating capacity equal 1,200 MW (1,000 MW owned by CMS and 200 MW owned by DTE).18 Expected electric generating capacity additions by 2016 in MISO Zone 7 are 860 MW, including 540 MW ofnatural gas-fired generating capacity and 320 MW of wind capacity. The MISO electric reliability assessments discount wind capacity additions by 85% owing to the intermittent generation pattern driven by variable wind conditions.

Current electric energy and capacity prices are not high enough to cover the average total cost of new power supply. As a resnlt, the current pipeline of new supply development is not adequate to keep overall demand and supply in balance in the years ahead. Power supply underinvestment is increasing the probability of a power supply shortfall in Michigan's Lower Peninsula around 2020. The most recent regional electric reliability survey projects that power supply will fall 1,200-1,300 MW short of the expected MISO Zone 7 capacity requirement in 2016. To put this shortfall in context, the expected Michigan Lower Peninsula (MISO Zone 7) capacity requirement for 2016 is 24.3 GW. For the next few years, however, the capacity surplus in other MISO zones can make up for this Zone 7 capacity deficiency, but the survey also notes that these conditions will last only through 2019. The survey concludes that additional power supply resources are required to ensure sufficient reliability beyond 2019. The implication is that planning and construction of these additional resources needs to begin now in order to have the needed power supply in place five years from now.1

'

The concern over power reliability in the Michigan Lower Peninsula, rather than in the entire state, arises because the adequacy ofinstalled capacity is not defined by political boundaries. Instead, power reliability assessment is defined by the power grid-the wires that physically interconnect homes and businesses with power plants. Power grid operation is complex; and consequently, the degree of transmission network interconnection defines the separate regional power zones for balancing electric demand and supply (see Figure 10).

Michigan's power zones are part of two larger regional power systems. Most of the Michigan power sector is in MISO, and the remainder is in PJM. Both power systems rely on independent third parties to coordinate and orchestrate power system operations. MISO and PJM operate wholesale electric energy markets and use marketclearing prices to orchestrate the efficient utilization of existing power supply resources, within the existing transmission constraints, to generate

Figure 10

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18. CMS retirements are detailed in MPSC Case 17473, opened 9 September 2013. DTE retirements are reported in "DTE Energy to close two units at Trenton Channel Power Plant in 2016,"The News-Herald, 24 July 2014.

19. 2015 OMS MISOSurvey Results, July 2015.

© 2015 IHS 24 July 2015



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and deliver enough electric energy to meet consumer needs at any point in time. In addition, both regional operators run capacity markets-although employing quite different approaches-to establish a capacity price intended to help keep demand and supply in balance over the long run.

Pricing hubs in each zone are located at points where the transmission network enables rival generators to compete to deliver electric generation to meet aggregate consumer needs. MISO Zone 7 has its own pricing hubs for both electric energy and capacity commodities.

Michigan cannot rely on outside supply coming to the rescue when a power shortage develops. High-voltage transmission lines link MISO Zone 7 with power supply in PJM, Ontario, and MISO Zone 2. These linkages provide a combined capacity import capability of3,884 MW. However, the projected MISO Zone 7 power supply shortfall already takes this transmission transfer capability into account in the reliability assessment, so there is no additional power supply from outside MISO Zone 7 that could relieve the power supply shortfall.

Indeed, transmission linkages have the potential to aggravate Michigan's reliability challenges. MISO and PJM capacity market designs are different. They produce different pricing patterns and create incentives for power plants to switch supply in the short run to whichever market provides greater compensation for capacity. Figure 11 shows that the PJM capacity market produces a higher Figure 11 payment than the MISO Zone 7 capacity market. As a result, power suppliers have an economic incentive to move their supply to the area of greatest return. For example,

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the Covert Generating Company announced a transmission project on 23 September 2014 that will enable this (approximately) 1,000 MW natural gasfired power plant to sell its capacity into the PJM capacity marketplace instead ofinto MISO.

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(see the box "Presque Isle highlights Michigan's retail open access dilemma").

Source: IHS 8iergy, P..!111, 1111180 ©2015 IHS

The current opportunity to realign Michigan regulatory processes and market realities All too often, it takes a crisis to force changes in the power industry structure. In the case of the California power crisis, the evidence that underinvestment was preventing power supply from keeping up with demand was apparent, but actions did not materialize until after a severe shortage unfolded. More recently, the problems of natural gas and power supply coordination simmered for years on a back burner until the winter 2013/14 polar vortex forced power systems to reevaluate how they defined and paid for firm power supply.

Michigan's misalignments in its hybrid power industry structure create problems-unfair cost burdens, the discriminatory switching option, and the increasing probability for power system demand and supply instability. The misalignments between regulation and the marketplace shift roughly $300 million each year of costs away from

© 2015 IHS 25 July 2015



Page 36 of 43


Presque Isle highlights Michigan's retail open access dilemma

t An ongoing situation in Michigan and Wisconsin highlights t_he consequences and complications thatcan · arise as a result of aretail open access option •

. Jn 2008, Michigan.allowed an exemption in retail open ac:cess sestrictions and excluded mining companies i{from the 10% cap for retail open access.load. This gave miningcompanies an unconstrained ability to switch · irto competitive eleqtric service and back. In 2013, .cl_ifbNatu~al Resources (CNR) exE:rcised thi,; right and .notified its regulated service provider, we Energi_~s of Wisconsin, that it was switching to compe.t.itivE; ·:supplier Integrys Energy Services Inc. ofChicago. CNRrepresented 85% of We Energies Upper Peninsula

i\load. With such a substantial decreas.e in demand.and the pending costs of retrofits to meetforthcoming :, clean air standards, We Energies decided to close the Presque lsl.e coal-.fired power plant serving the area:

However, MISO (the.regiona_I grid operator) prohibited We Energies from cl?sing .the. plant bec.ause doing so .:, would threatEon regional grid reli.ability. MISO offered the plant a System Support Resource (SSR) contract to lkeep itonline. The$52 million annual cost of thisSSR contrn<:tw<;s dividedamongall transmission line t customers, an are.a much broaderthantheUPPerPeninsula.Consumer backlash arose in\l\/is~onsin ov~r ~he cost increase and all?c<iti?n ?f 92% of the c?sts to customers outside the Uppe;>rPenirisula, .Further, the f .Wisconsin Public Utilities Commission disputed the .allocation of cbargesto FERC, which ruled in its. favor in

Fl July _2014. . · ):'.,'

iii'\nJanuary 2015, a tentative deal was reached whereby We Energies agreed to se;>ll its utility business to !~.Upper Peninsula Power Co. (UPPCO),. incluc1ing the Presque Isle power plant for $land the custor-ners and l;,_operations of its 10 hydroelectric dams, but not the _dam a~sets: Notably, the plan also required that the · . mining company, CNR, buy power from UPPcO until thePresq~e plant shuts down-.anE;stimatE?d fi~e years.

In February 2015, FERC gave MISO 60days topropo~e a new method of all.ocatingthe SSRcosts ina [!• follow'Up to its earlier finding thatthe costalloc_ation method_ was "unjust, unreasonabl_e and unduly i discriminatory or: preferential."' · · · · · · ·

1\ 'f-Jowever, in. M'."rch 20l!'), vve Energies reversed courseanddecidedagainst selling the Upper Pehinsula plant ('. to the new utility, anp C_NR'."9re.ed not totake advantage of the retail open a~~ess law, On 23_,,,priL 2()15, ttie V: 0ichigan PSc approved We Energies' prop?sed acquisition of lntE?grys. \/\le Energies will not receive '."n SSR ft .. ~ontract forthe Presque Isle power plant as long <;s the min~sremain full-requi.rerrientele;>ctri<: customers of i:i.We Energies untiltbe e<;rlier of 31 Dece.mber 2019 or the;> dat.e that anew cleangeneratio~ plant .. · [.:.commences operation on the Upper Peninsula of Michigan. FERc and the Wisconsin PSC have approved the (j \llilrger,\but reviews are pending before the state PSCs in Illinois and Minnesotar it',_ ... _ .. __ ··--·--~-~-

;:: ~E·R c_ brd_~~ >'.156 Fe.RC 6J:;1ci_4; ''.. 19 ·F~tirUary. 20 ls;- https://WWw. fe rc.-QoV /Wh_ats~new /c'orri ;,,: -_r~ie'et/2ci_iS10ii9is1~:~3.P~t: ·_aC_C~-5;~~ '.2'i:F-~b/tiah1 '.::'2015. . ' '

kI;it~Michigan PSC Case·~o: u-t7_6s2,:23APriL2oi:s_.

a minority of Michigan consumers (retail open access customers account for a little over 10% of the state's power consumption and approximately 0.5% of customers) to the majority of customers, the utility ratepayers. Doing nothing continues the unfair distribution of power supply costs and increases the probability of a serious power shortage in the Lower Peninsula around 2020.

Rather than wait for misalignments to create a crisis, Michigan has the opportunity to address its power sector challenges by realigning regulation to market realities in a way tbat ensures consumers get reliable, affordable, and sustainable electricity supply in the long run with a fair distribution of the associated cost burden.

The time has come for Michigan to realign its regulation with the regional power marketplace. Michigan has two primary options: phase out partial retail open access or adjust the partial retail open access program.

© 2015 lHS 26 July 2015



Page 37 of 43


Phasing out partial retail open access The first option is the most straightforward approach and simply involves a phaseout of partial retail open access by mandating a shift back to regulated utility supply. A planned phaseout allows utilities to incorporate all load into their integrated planning process. For example, this is the course ofaction taken in the state of Virginia in the wake of the California power crisis. ·

A plan to phase out retail open access would not have to displace existing AESs; they would have to source power supply from utilities at a nondiscriminatory cost. Such an arrangement has been in place for decades to allow municipally owned and rural electric cooperatives to operate alongside regulated utilities. This arrangement would allow continued competition among AESs in other areas, such as demand-side capabilities or distributed generation options.

Altering partial retail open access The second option would alter the partial retail open access program-a less definitive and more complex approach. A two-pronged plan would add a system benefit surcharge and also add a rule requiring AESs to demonstrate a firm forward supply arrangement for the projected needs of their current customers to provide enough lead time (at least five to seven years) to develop not only peaking units but also the cycling and base-load power plants necessary for efficient and reliable power supply.

A systemwide benefits surcharge on the power purchased by retail open access customers can level the cost burden of utility investments that provide systemwide efficiency, risk management, and environmental benefits. Such a charge could eliminate the average annual free rider cost shift of roughly $300 million from retail open access customers onto utility ratepayers. However, this approach to the free rider problem does not solve the discriminatory option problem that gives retail open access customers an incentive to purchase capacity from the lower of regulated rates or market prices.

Both prongs of this approach to alter partial retail open access need to be part of the solution. Just altering the retail open access by adding a system benefit surcharge without also requiring a multiyear firm forward supply arrangement for projected consumer demand would worsen the discriminatory switching option and create greater instability in balancing power demand and supply and ensuring reliability in the long run.

Adding a systemwide benefits surcharge alone can equalize the average cost of power supply from AES and utilities; but it would not alter the difference in cost variations through time. The regulated power costs would continue to be relatively stable because it reflects the slowly changing average total costs. On the other hand, the cost of power from the AES would still vary more because of the boom-and-bust price pattern of market capacity prices and the variability of energy prices linl<ed to the ups and downs of fossil fuel prices, especially natural gas. But reducing the difference between the average regulated and average AES power costs while differences remain in the cost variability around those averages will increase the frequency of customers exercising the option to switch back and forth. Thus the value of the retail open access option available to some but not all customers will increase. The average annual value of the retail open access switching option would rise from the current small value to around $41 million. Hence, mitigating this discriminatory customer option requires implementing both a systemwide benefits charge on AES consumers and a multiyear firm forward supply arrangement for projected consumer demand.

Conclusion The implications of the current Michigan power sector challenges are clear-Michigan must realign its regulation with the market realities. Under the status quo, Michigan's hybrid power sector shifts roughly $300 million per year of costs away from a minority of Michigan consumers to the majority of customers, the utility ratepayers.

The need for corrective actions is urgent because the probability of unreliable power supply is increasing in Michigan. This misalignment between short-run customer switching and long-run supply planning is one reason why the current pipeline of new supply will not be able to keep up with system demand increases or replace retiring generating resources. The margin for error in balancing power demand and supply is small. In Michigan, a reserve margin ofl4.8% is required

© 2015 IHS 27 July 2015

----------------------------------------------- -·---------



Page 38 of 43

JHS Energy I Meeting the Michigan Power Sector Challenge

to reliably balance power demand and supply. Dropping just S percentage points short of the target reserve margin substantially increases the probability of serious power system problems-emergency load shedding, brownouts, and price spikes altogether similar to what happened in California in 2000-01.

By addressing the misalignments in the current hybrid power industry that create an unfair cost burden, a discriminatory switching option, and the increasing probability for power system demand and supply instability, Michigan can ensure that its power system remains reliable, efficient, and environmentally compliant. Corrective actions will enable a fair and nondiscriminatory distribution of costs to customer classes and maintain the competitiveness of electric input costs to Michigan businesses operating in the global economy.

© 2015 IHS 28 July 2015



Page 39 of 43


Appendix: MISO capacity market design produces a boom-and-bust price pattern Boom-and-bust capacity price patterns are a predictable result of the MISO formal capacity market design incorporating inelastic demand and supply curves. Demand and supply conditions vary from one year to the next, and market demand and supply curves are unlikely to line up and allow MISO Zone 7 prices to consistently clear at the average total cost of new supply. Instead, demand and supply fluctuations around the market balance point will produce a boom-and-bust price pattern.

A well-functioning capacity market should consistently produce a market-clearing price close to the average total cost of supply when demand and supply are close to balance. However, a market with price-inelastic demand and supply curves tends to produce volatile prices aronnd average total costs because of normal short-run variations in demand and supply conditions when demand and supply are close to long-run balance.

The price elasticity of demand measures the sensitivity of aggregate consumer power demand to price. If demand is relatively sensitive to price, then a price change will cause a more proportional change in demand, and so the demand is considered price elastic. For example, if a 10% increase in the price causes a greater than 10% decline in demand, then demand is price elastic. Conversely, if demand is relatively insensitive to price, then a price change will produce a less than proportional change in demand, and demand is considered price inelastic.

Graphically, the slope in a demand curve indicates the sensitivity to price. All else equal, a more horizontal demand curve indicates more sensitivity to price (price-elastic demand) and a steeper demand curve indicates less sensitivity of demand to price (price-inelastic demand). If demand is independent of price, then the demand curve is perfectly inelastic and vertical.

A concept similar to demand elasticity describes the sensitivity of supply to price. Capacity supply is more responsive to a forward price change (a price for supply set years into the future) compared to a price signal for supply just months ahead. Price elasticity is higher because a price signal years in advance provides enough time to respond with the design, siting, permitting, and construction of new supply. By contrast, typical power development lead times preclude altering supply much within a few months in response to a change in the capacity price. Graphically, an inelastic capacity supply curve has a steeper upward slope compared to a more elastic supply curve.

A well-functioning capacity market will balance demand and supply at a price sufficient to cover the average total cost of supply. Figure A-1 shows a market with the characteristics of the MISO capacity market-a vertical demand curve and an inelastic supply curve-intersecting to produce a market-clearing price equal to the average total cost of production.

Inelastic demand and supply curves are steeply sloping, and these shapes frame an unlikely and fragile market outcome in which price equals average total cost. The result is unlikely because all of the other factors that influence demand and supply need to position the intersection of these curves close to the average total cost. The result is fragile because even if demand and supply initially line up to produce a price equal to average total cost, any slight shift in demand or supply conditions will move the price significantly away from the average total cost. As a result, the normal

© 2015 JHS

Figure A-1

«~«\' ~"~~Tei "'>"W'"' c" '" "''\;; " " ~ ~

!?'.erf~'i!J~ ip:~lastic ·aeih'\tl'~a!1_c(~"!'!!1l{ely inelastic; s_u,pply-ln balance:- _

supply

·~ .. Average total cost

Demand0

o, Quantity

© 201!> IHS: 50505-3 Source: IHS En~rgy

29 July 2015



Page 40 of 43


variations in demand and supply conditions will result in dramatic capacity price increases or decreases-the boom-andbust price pattern.

Bust prices arise whenever slight shifts in demand or supply conditions throw the market out oflong-run balance by increasing supply or reducing demand. For example, an economic downturn can reduce demand for a few years by several percent from expected long-run levels. A slight decline in demand shifts the demand curve to the left and causes the market-clearing price to fall dramatically-producing bust prices (see Figure A-2).

Boom prices arise whenever slight shifts in demand or supply conditions throw the market out oflong-run balance by decreasing supply or increasing demand. For example, the multiyear lead time required to develop new power supply means that with a small error in forecasting demand that results in an underestimate, planned capacity will not meet actual demand. Figure A-3 illustrates how this error shifts the demand curve to the right of the expected level and causes prices to rise significantly above average total costproducing boom prices.

When demand and supply are inelastic, then slight changes in power supply caused by the lumpy size of power plant additions and retirements trigger boomand-bust price movements the same way as the slight changes in demand.

A boom-and-bust price pattern is not a typical market outcome when demand and supply curves are more price elastic. Greater-than-proportional changes in demand or supply in response to price changes mean that the shape of the demand and supply curves would be more horizontal. Figure A-4 shows that the same slight demand decline that produced bust prices with inelastic demand and supply curves will instead produce a small price change. As a result, the price level is still close to the average total cost when demand and supply curves are more elastic to price. Typically, this balance is not achieved in the electricity sector because the

Figure A-2

·~ 0.

Source: IHS Energy

Figure A-3

Source: IHS Energy

demand and supply curves are not usually elastic.

© 2015 IHS

Average total cost

Bust price

Supply

A shift in demand or supply in a market with a vertical demand curve and relatively inelastic supply produces a relatively large change in price and h. P > I::. Q.

Here, a small reduction In demand results in a significant price drop.

Demandl .. Demand0

Quantity

Boom price

Average total cost

Quantity

30

tJ wis IHs: sosos-1:

A shift in demand or supply in a market with a vertical demand

~ curve and relatively inelastic supply produces a relatively large change in price and l::.P > l::.Q.

Here, a small increase in demand results in a significant price increase.

t> 2015 IHS: Sobo~-~

July 2015



Page 41 of 43


Figure A-4

© 2015 IHS

A shift in demand or supply in a market with relatively elastic supply and demand produces a relatively small change in price and A P < A Q.

Quantity o, o,

31 July 2015



Page 42 of 43

© 2015 IHS. No portion of this report may be reproduced, reused, or otherwise distributed in any form without prior written consent.



Page 43 of 43

216048733.1 07411/312567

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION* * * * *

In the matter, on the Commission’s own motion,to open a docket to implement the provisions ofSection 6w of 2016 PA 341 forCONSUMERS ENERGY COMPANY’Sservice territory.

))))))

Case No. U-18239

ALJ Mark D. Eyster

ASSOCIATION OF BUSINESSES ADVOCATING TARIFF EQUITY,RESPONSE TO CONSUMERS ENERGY COMPANY’S

SECOND DISCOVERY REQUESTS

The Association of Businesses Advocating Tariff Equity (“ABATE”), by its attorneys,

Clark Hill PLC, submit the following response to Consumers Energy Company’s (“CECo” or the

“Company”) first data requests to the Association of Businesses Advocating Tariff Equity.


See page 8 of ABATE’s Position Summary filed on July 17, 2017 in Case No. U-

18197. Please specify and describe the “separate Local SRM Capacity Charge”

referenced and describe its calculation and administration.

Response:

ABATE did not propose a specific method to calculate and administer the

separate Local SRM Capacity Charge. ABATE envisions the details with respect

to the calculation and administration of the charge would be addressed in a follow

up proceeding either within U-18197 or in a new case initiated by the

Commission. ABATE would also note that new local incremental generation

capacity could not not be added without at least a two year lead time. Therefore,

MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company



Page 1 of 7

216048733.1 07411/312567

the specifics of the calculation and administration of the separate Local SRM

Capacity Charge will not need to be decided upon by the Commission prior to the

MISO 2018-2019 Planning Year.


See page 9, footnote 12 of ABATE’s Position Summary filed on July 17, 2017 in

Case No. U-18197.

a. Identify and specify the location of the referenced “2,000 MWs of

generation built by AES’ [sic] between 2000 and 2008.”

b. Specify the date on which each of the sources of generation included in

the referenced 2,000 MW figure went into service.

c. Specify whether each of the sources of generation included in the

referenced 2,000 MW figure is still operational.

d. Specify the nameplate capacity of each source of generation included in

the referenced 2,000 MW figure.

e. Identify and specify generation built by Alternative Electric Suppliers

(“AESs”) serving retail load in Michigan between 2009 to date.

f. Provide the source(s) and the calculation for the referenced “Utilities’ $2.2

Billion of stranded-cost recovery from 2008 through 2016,” including, but

not limited to, MPSC case which authorized the referenced recoveries, as

well as all calculations underlying the stated recovery figure.



Page 2 of 7

216048733.1 07411/312567

Response:

a. ABATE objects to this entire discovery request as it seeks information

related to a public position statement made in U-18197 for which

discovery is not permitted; is not calculated to lead to any data or

information relevant to this proceeding; and seeks information already in

the possession of Consumers. Notwithstanding that objection, ABATE

states that the generation facilities listed below were built between 2000

and 2008 by independents (i.e., non-utilities) for a competitive

marketplace. ABATE recognizes that not all of the owners of these

facilities were licensed “AESs” or affiliates of AESs:

Dearborn Industrial Generation 710 MW 2001

Zeeland Generating Station 868 MW 2001

New Covert Power Plant 1159 MW 2004

Renaissance Power of Carson City 680 MW 2002

Kinder Morgan – Jackson 564 MW 2002

The total generation constructed between 2000 and 2008 by non-utilities

was thus nearly 4,000 MWs.

b. Notwithstanding ABATE’s objection, see answer to CE-AB-4a above.

c. Notwithstanding ABATE’s objection, ABATE states that all are still

operational. Notably, Consumers and DTE have each purchased some of

these plants. In 2005, the MPSC, at the utilities urging, started adding

charges to customer choice capacity (making it less economic) and the

legislature in 2006 began debating ending competition. Thus, the



Page 3 of 7

216048733.1 07411/312567

competitive market declined as did the addition of new power plants for a

competitive marketplace.

d. Notwithstanding ABATE’s objection, see answer to CE-AB-4a above.

e. Notwithstanding ABATE’s objection, ABATE states that after the 90%

of the competitive market was eliminated in 2008 by virtue of Act 286,

ABATE is not specifically aware of any “generation built by Alternative

Electric Suppliers (“AESs”) serving retail load in Michigan between

2009 to date,” but there may be some.

f. Notwithstanding ABATE’s objection, ABATE states that the $2.2 billion

number for stranded cost for both CECo and DTE has been widely

recognized and used by legislators, regulators, and even utilities since Acts

141 and 142 of 2000, nearly 17 years. A more robust description is

contained in the October 31, 2013 Study performed by the Mackinac

Center for Public Policy which states, among other things, that “Public

Act 142, passed as a package with P.A. 141 in 2000, gave state guarantees

of $2.2 billion in utility refinancing to lower incumbent utility costs. In

addition, the two utilities, DTE Energy and Consumers Energy, were

guaranteed compensation if electric restructuring required them to close

facilities.” https://www.mackinac.org/19556#_ftn9 Furthermore, the 2000

SEC 10-K of both DTE and Consumers state that the utilities planned to

issue approximately $1.75 billion and $470 million, respectively, in

securitization bonds related to stranded costs. The MPSC cases which

approved the precise amounts for Consumers and DTE are public records



Page 4 of 7

216048733.1 07411/312567

readily available. Notably, Consumers was a party to its cases and

followed DTE’s stranded cost cases closely, and the information is or

already has been within Consumers’ possession. ABATE has not

assembled the data as requested and therefore it is not in its possession,

and it objects to having to create or re-create it.


Reference pages 22-23 of James R. Dauphinais’ prefiled testimony, where he

references an assumption that no Retail Open Access (“ROA”) customers will pay

Consumers Energy’s State Reliability Mechanism (“SRM”) capacity charge.

a. Please provide any estimates or forecasts of ROA customers or load which

will become subject to the SRM capacity charge during the period 2018-

2025.

b. Please provide any estimates or forecasts of ROA customer billing

determinants which will apply to the SRM capacity charge during the

period 2018-2015.

c. Please provide copies of any documents consulted or used in conjunction

with or which relate to the estimates or forecasts referenced in subparts (a)

and (b) of this discovery question.

Response:

a. ABATE has none. It is not possible at this time to reasonably estimate or

forecast the amount of ROA customer load that will be subject to the SRM

capacity charge. However, that does not make it reasonable to set the



Page 5 of 7

216048733.1 07411/312567

initial SRM capacity charge based on the assumption that no ROA

customer load will be subject to it. This is why Mr. Dauphinais is

recommending the SRM Capacity charge be updated upon the completion

of Consumers’ general rate case in U-18322 once the initial amount of

ROA customer load subject to the SRM capacity charge is known along

with the incremental cost to Consumers to provide capacity to those ROA

customers.

b. Please see the response to a.

c. Please see the response to a.


Reference pages 36-37 of Mr. Dauphinais’ prefiled testimony, where he describes

a “separate local SRM Capacity Charge.”

a. Provide any estimates or forecasts of the referenced separate local SRM

Capacity Charge.

b. Explain how the separate local SRM Capacity Charge would be

determined, including but not limited to: (i) the methodology; (ii) the

proceeding; (iii) how it will be applied to customer bills.

Response:

a. ABATE has none. At this time, no specific need for incremental local

capacity has been identified. Therefore, it is not possible at this time to

provide any forecasts or estimates for the proposed separate local SRM

capacity charge. This said, as explained in Mr. Dauphinais’ direct



Page 6 of 7

216048733.1 07411/312567

testimony, ABATE expects the per unit cost of incremental local capacity

to be equal to or less than the MISO CONE value.

b. Please see the response to Data Request No.18239-CE-AB-3.

Respectfully submitted,

CLARK HILL PLC

By: ____________________________________Michael J. Pattwell (P72419)Sean P. Gallagher (P73108)Stephen A. Campbell (P76684)Attorneys for Association of BusinessesAdvocating Tariff Equity212 East Grand River AvenueLansing, Michigan 48906Office: [email protected]@clarkhill.com

Date: July 31, 2017 [email protected]

Digitally signed by: Michael J. PattwellDN: CN = Michael J. Pattwell email = [email protected] C = US O = Clark Hill, PLCDate: 2017.07.31 15:58:14 -05'00'

Michael J. Pattwell



Page 7 of 7

2017 OMS MISO Survey ResultsFurthering our joint commitment to regional resource assessment and

transparency in the MISO region, OMS and MISO are pleased to announce the results of the 2017 OMS MISO Survey

June 2017




Page 1 of 18

The 2017 OMS MISO survey projects sufficient resources to manage resource adequacy risk

• In 2018, changes in resource commitment and decreased demand lead to a regional surplus• The region is projected to have 2.7 GW to 4.8 GW resources in excess of the

regional requirement, based on responses from over 96% of MISO load

• Decreases in demand forecast leads to a lower resource adequacy risk than previously projected• 2018 summer peak forecasts decreased 2.5 GWs from 2017 projections• Regional 5 year growth rate is 0.5%, down from 0.8% last year

• Beyond 2018, continued focus on load growth variations and generation retirements will reduce uncertainty in future resource adequacy assessments

2



Page 2 of 18

Understanding Resource Adequacy Requirements

3

• Load serving entities within each zone must have sufficient resources to meet load and required reserves

• Surplus resources may be used by load serving entities with resource shortages to meet reserve requirements



Page 3 of 18

1.0

1.11.8

1.9

1.9

1.1

1.52.3

2.5

2.8

2018 2019 2020 2021 2022

Existing resources, potential retirements, and new resources create a range of resource balances

4

Projected Regional Capacity Positionin Installed Capacity (ICAP)

GW (% Reserves)

4.8 (19.6%)

6.6 (21.0%)

3.2 (18.3%)2.6 (17.9%)

0.7 (16.3%)

• Regional outlook includes projected constraints on capacity, including Capacity Export Limits and the Sub-regional Power Balance Constraint• These figures will change as future capacity plans are solidified by load serving entities and state commissions. • Potential New Capacity represents 35% of the capacity in the final stage of the MISO Generator Interconnection queue, as of May 11, 2017.• Potentially Unavailable Resources includes potential retirements and capacity which may be constrained by future firm sales across the Sub-

regional Power Balance Constraint

2.7 (17.9%)

3.9 (18.9%)

7.3 (21.6%)

5.4 (20.0%)

Potential New Capacity

Potentially Unavailable Resources

Committed Capacity Projections

1 da

y in

10

PRM

(15.

8%)

7.0 (21.3%)



Page 4 of 18

-0.4

2.5

0.40.9

2.1 2.22.7

Regional capacity balances increased largely due to lower demand forecasts

5

Regional 2018 OutlookCommitted Capacity Projection Variations

since 2016 OMS MISO SurveyIn GW (ICAP)

ForecastedRegional Deficit: 2016 OMS-MISO

Survey

IncreasedAvailability of

Existing Resourcessince 2016

ForecastedRegional Surplus:

2017 OMS-MISO Survey

IncreasedReserve

Requirement due to Higher Forced

Outage Rates

ForecastedLoad

Reductions

New Resourcessince 2016

DecreasedAvailability of


New resources include resources with newly signed Interconnection Agreements and new Load Modifying ResourcesDecreased availability results from new retirements and more binding transfer limitationsIncreased availability results from deferred retirements and internal resources with reduced commitments to non-MISO load



Page 5 of 18

-1.6

0.40.0

0.4

1.8

0.3

0.7

Activity in Illinois resulted in much of the year-over-year regional change; continued action is required to achieve forecasted balances

6

ForecastedZone 4 Deficit:

2016 OMS-MISO Survey

IncreasedAvailability of


ForecastedZone 4

Surplus: 2017 OMS-

MISO Survey

IncreasedReserve

Requirement due to Higher Forced

Outage Rates

ForecastedLoad

Reductions

New Resourcessince 2016

Net Zonal Transfers to non-Zone 4

loads

New resources include resources with newly signed Interconnection Agreements and new Load Modifying ResourcesIncreased availability results from deferred retirements and internal resources with reduced commitments to non-MISO loadPositions include reported inter-zonal transfers, but do not reflect other possible transfers between zones

Zone 4 (Illinois) 2018 Outlook Committed Capacity Projection Variations

since 2016 OMS MISO SurveyIn GW (ICAP)



Page 6 of 18

2.1

2.6 4.1 4.4

4.7

2018 2019 2020 2021 2022

1 da

y in

10

PRM

2.12.6

4.1 4.44.7

2018 2019 2020 2021 2022

1 da

y in

10

PRM

Demand forecast variation creates risk for forward-looking resource adequacy projections

77

Projected Capacity Positionin ICAP GW (% Reserves)

2.8 (18.0%)4.3 (19.3%)

0.2 (16.1%) -0.5 (15.6%)-2.4 (14.1%)

0.7 (16.1%) 1.7 (17.3%)

4.3 (19.3%) 3.9 (19.0%)

2.3 (17.5%)

Potential Capacity Projections

Committed Capacity Projections

2017 SurveyAs Reported

4.8 (19.6%)

6.6 (21.0%)

3.2 (18.3%) 2.6 (17.9%) 0.7 (16.3%)2.7 (17.9%) 3.9 (18.9%)

7.3 (21.6%) 7.0 (21.3%)

5.4 (20.0%)

Potential Capacity includes potential new capacity and potentially unavailable resources

2017 Survey with 2016 Load and

Requirement



Page 7 of 18

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

2018 2019 2020 2021 2022

Future resource ranges will shift as planned generation interconnections are firmed up

8 Wind and solar resources are represented at their expected capacity creditNon-ready projects will be deemed withdrawn, as of June 15th, with an option to move to final studies

Potential Generation Additions, in GW

Not yet submitted Non-ready projects Final studies not included in potential capacity Final studies included in potential capacitySigned agreements

Included in potential capacity

Included in committed capacity

Not included in regional or zonal totals



Page 8 of 18

One day in tenPRM (15.8%)

In 2018, regional surpluses are sufficient to cover areas with resource deficits

9

1 2 3 4 6 7 8 9

2018 Outlook (ICAP GW)

Lower MIMN, MT, ND, SD, West WI

East WI and

Upper MI

IA IL INand KY

AR LA and TX

0.9 to1.1

0.6

0.5 to 1.0

-0.3

0.4 to 0.7

0.8 to 1.1

1.0 to 1.5

5MO

0.7 to 1.6

10MS

-1.0 to -0.7

0.8 to 0.9

4.8 (19.6%)

2018 Outlook, ICAP GW (% Reserves)

Potential Capacity Projection

Committed Capacity Projection

2.7(17.9%)

2.1

• Regional surpluses and potential resources are sufficient for all zones to serve their deficits while meeting local requirements.• Positions include reported inter-zonal transfers, but do not reflect other possible transfers between zones • Exports from Zone 1 were limited by the zone’s Capacity Export Limit to 0.6 GW• Results include load, but not identified resources, from some non-jurisdictional load in Zone 5• Exports from Zones 8, 9, and 10 were limited by the Sub-regional Power Balance Constraint to 1.2 GW



Page 9 of 18

One day in tenPRM (15.8%)

4.7

Continued focus on load growth variations and generation retirements will reduce uncertainty around future resource adequacy assessments

10

1 2 3 4 6 7 8 9

2022 Outlook (ICAP GW)

Lower MIMN, MT, ND, SD, West WI

East WI and

Upper MI

IA IL INand KY

AR LA and TX

5.4 (20.0%)

2022 Outlook, ICAP GW (% Reserves)

0.5 to 1.1

0.2 to 0.50.2 to 0.9

-0.4

0.2 to 1.5 0.7 to 1.5

5MO

0.4 to 1.5

10MS

-1.5 to -1.1

0.6 to 0.9

-0.2 to -0.1

Potential Capacity Projection

Committed Capacity Projection

0.7 (16.3%)

0.7

• Regional surpluses and potential resources are sufficient for all zones to serve their deficits while meeting local requirements• Positions include reported inter-zonal transfers, but do not reflect other possible transfers between zones • Results include load, but not identified resources, from some non-jurisdictional load in Zone 5• Exports from Zones 8, 9, and 10 were limited by the Sub-regional Power Balance Constraint to 1.5 GW in committed capacity

projections and 1.9 GW in potential capacity projections



Page 10 of 18

Appendix



Page 11 of 18

Understanding Resource Projections

• Committed Capacity Projections include resources committed to serving MISO load• Resources within the rate base of MISO utilities• New generators with signed interconnection agreements• External resources with firm contracts to MISO load• Non-rate base units without announced retirements or commitments to non-MISO load

• Potential Capacity Projections include resources that may be available to serve MISO load but do not have firm commitments to do so• Potential retirements or suspensions• 35% of new resources in the Definitive Planning Phase (DPP) of the MISO queue

• Unavailable resources are not included in the survey totals• Resources with firm commitments to non-MISO load• Resources with finalized retirements or suspensions• Potential new generators without a signed Generator Interconnection Agreement or

generators which have not entered the DPP phase of the queue

12



Page 12 of 18

All projected capacity is not available to serveload outside of its zone due to transfer limitations

13

0.6 GW

0.5 GW

0.4 GW

-0.3 GW

0.6 GW

1.2 GW

2018 Committed Capacity projection available to

Support Other Zones (ICAP)

Transfer Limited CapacityProjected surplus

Projected deficit

0.7 GW

-1.0 GW

• Regional surpluses and potential resources are sufficient for all zones to serve their deficits while meeting local requirements

• Results include load, but not identified resources, from some non-jurisdictional load in Zone 5



Page 13 of 18

0.13% 0.47%

15.2% 15.8%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

16.0%

18.0%

16/17 PY Load ForecastReduction

Increase in OutageRates

17/18 PY

Percent (%)

Planning Reserve Margin (PRM)2016 – 2017 Variance

14



Page 14 of 18

OMS MISO Survey 2017 ImprovementsInclusion of 35% of DPP Projects• Using a sample set of gas projects that have gone

through the Definitive Planning Phase (DPP) between 2012 through 2016, the following numbers apply:• 37% withdraw rate (projects that entered the DPP and later

withdrew)• 26% success rate (projects that have completed GIAs)• That leaves a potential success rate of somewhere in the middle

(between 26% – 63%) for those projects still in the DPP study• Data focused on gas projects to represent expected base load

capacity build

• After discussion with stakeholders, MISO added 35% of DPP projects into zonal and regional values as potential resources

15



Page 15 of 18

Interconnection Requests in the MISO Queue from 2012 – 2016 (Gas Resources Only)

16



Page 16 of 18

Changes from 2016 Survey to the 2017 Survey for Planning Year 2018

Changes in Forecasted Load Changes (MW) Reserve Requirement Changes (MW) Planning Resources Changes (MW)

Zone 1 (317.7) 54.2 (461.7)

Zone 2 (129.8) 55.1 52.1

Zone 3 (253.2) 16.2 550.4

Zone 4 (441.0) (11.2) 2130.4

Zone 5 (431.1) (17.7) 40.6

Zone 6 (327.6) 54.0 (84.8)

Zone 7 (366.7) 67.7 (776.94)

Zone 8 80.8 59.6 (95.4)

Zone 9 (154.9) 93.9 (115.7)

Zone 10 (159.9) 3.5 58.9

Regional (2.5) 0.4 1.0

17



Page 17 of 18

Zonal breakdown for retirements vs potential new resources for 2018 and 2022Planning Year 2018

LRZPotential NewCapacity (MW)

PotentiallyUnavailable Resources

(MW)

Zone 1 250.8 0.0

Zone 2 28.6 0.0

Zone 3 272.5 235.3

Zone 4 60.9 750.7

Zone 5 16.6 0.0

Zone 6 259.3 0.0

Zone 7 187.2 0.0

Regional Rollup 1075.9 986.0

Zone 8 70.0 0.0

Zone 9 209.0 103.4

Zone 10 17.5 469.8

MISO 1372.4 1559.2

18

Planning Year 2022

LRZPotential NewCapacity (MW)

PotentiallyUnavailable Resources

(MW)

Zone 1 597.4 0.0

Zone 2 365.6 0.0

Zone 3 373.6 336.1

Zone 4 277.9 865.5

Zone 5 61.0 0.0

Zone 6 710.5 314.5

Zone 7 408.6 19.3

Regional Rollup 2794.6 1935.4

Zone 8 316.2 0.0

Zone 9 907.5 382.6

Zone 10 88.2 704.6

MISO 4106.4 2622.6

* Potential Capacity Zones 8, 9, and 10 limited in regional rollups due to South – North transfer limitations



Page 18 of 18


3

18239-CE-ST-6 Does Staff agree that Consumers Energy’s owned electric

generating plants provide capacity service? If the answer is anything but an

unqualified yes please explain your answer.

Answer

Assuming that “capacity service” means the provision of capacity to cover the

Company’s customers’ load/capacity requirements, insofar as the Company’s owned

electric generating plants’ capacity qualifies at MISO to cover the Company’s

capacity requirements at MISO, Staff agrees. However, it is important to note that

capacity service is only one of many services provided by the Company’s electric

generating plants.

Respondent: Nicholas M. Revere




Page 1 of 2


4

18239-CE-ST-7 Does Staff agree that Consumers Energy’s power purchase

contracts provide for the provision of capacity service? If the answer is anything but

an unqualified yes please explain your answer.

Answer Assuming that “capacity service” means the provision of capacity to cover the

Company’s customers’ load/capacity requirements, insofar as the contracts provide

capacity to the Company that qualifies at MISO to cover the Company’s capacity

requirements at MISO, Staff agrees. However, it is important to note that capacity

service is only one of many potential services provided by the Company’s power

purchase contracts. In general, these contracts also provide at least energy service.

Respondent: Nicholas M. Revere



Page 2 of 2

216068894.1 07411/312567


Please reference page 35, line 23 through page 36, line 2 of Mr. Dauphinais’

testimony.

a. Is it ABATE’s position that an ROA customer can “elect” to pay the

SRM capacity charge regardless of whether its alternative electric

supplier can meet the resource adequacy requirements established by

the MPSC pursuant to Section 6w of Act 341? Please explain your

answer.

Response:

a. No. It is ABATE’s position that a ROA customer should be able to

contractually agree with its AES with respect to whether or not , and to

what extent, the AES will self arrange capacity rather than utilize the

SRM Capacity Charge when serving the ROA customer. ABATE

envisions that such contractual arrangements would include a hold

harmless provision protecting the ROA customer if the AES ultimately

is unable to meet the resource adequacy requirements for the ROA

customers’ load.




Page 1 of 1

ps0817-1-230




)

PROOF OF SERVICE

STATE OF MICHIGAN ) ) SS

COUNTY OF JACKSON )

Tara L. Hilliard, being first duly sworn, deposes and says that she is employed in the Legal Department of Consumers Energy Company; that on August 7, 2017, she served an electronic copy of the Rebuttal Testimony and Exhibits of Consumers Energy Company Witnesses Josnelly C. Aponte, Laura M. Collins, and David F. Ronk, Jr. upon the persons listed in Attachment 1 hereto, at the e-mail addresses listed therein. She further states that she also served a hard copy of the same document to the Hon. Mark D. Eyster at the address listed in Attachment 1 by depositing the same in the United States mail in the City of Jackson, Michigan, with first-class postage thereon fully paid.

__________________________________________ Tara L. Hilliard

Subscribed and sworn to before me this 7th day of August, 2017.

_________________________________________ Melissa K. Harris, Notary Public State of Michigan, County of Jackson My Commission Expires: 06/11/20 Acting in the County of Jackson

ATTACHMENT 1 TO CASE NO. U-18239

sl0417-1-230 Page 1 of 3

Administrative Law Judge

Hon. Mark D. Eyster Administrative Law Judge 7109 West Saginaw Highway Post Office Box 30221 Lansing, MI 48909 E-Mail: [email protected]

Counsel for the Michigan Public Service Commission Staff

Meredith R. Beidler, Esq. Bryan A. Brandenburg, Esq. Lauren D. Donofrio, Esq. Assistant Attorneys General Public Service Division 7109 West Saginaw Highway Post Office Box 30221 Lansing, MI 48909 E-Mail: [email protected]

[email protected] [email protected]

Counsel for Attorney General, Bill Schuette

Celeste R. Gill, Esq. Assistant Attorney General ENRA Division 6th Floor Williams Building Post Office Box 30755 Lansing, MI 48909 E-Mail: [email protected] [email protected]

Counsel for the Sierra Club

Tracy J. Andrews, Esq. Christopher M. Bzdok, Esq. Kimberly Flynn, Legal Assistant Karla Gerds, Legal Assistant Olson, Bzdok & Howard, P.C. 420 East Front Street Traverse City, MI 49686 E-Mail: [email protected]

[email protected] [email protected] [email protected]

Counsel for Wal-Mart Stores East, LP and Sam’s East, Inc.

Melissa M. Horne, Esq. Higgins, Cavanagh & Cooney, LLP 10 Dorrance Street, Suite 400 Providence, RI 02903 E-Mail: [email protected]

Counsel for the Association of Businesses Advocating Tariff Equity (“ABATE”)

Michael Pattwell, Esq. Sean P. Gallagher, Esq. Clark Hill PLC 212 East Grand River Avenue Lansing, MI 48906 E-Mail: [email protected]

[email protected]

Stephen A. Campbell, Esq. Clark Hill PLC 500 Woodward Avenue, Suite 3500 Detroit, MI 48226 E-Mail: [email protected]

Consultants for ABATE

James R. Dauphinais Michael P. Gorman Brubaker & Associates, Inc. Physical Address 16690 Swingley Ridge Road, Suite 140 Chesterfield, MO 63017 Mailing Address Post Office Box 412000 St. Louis, MO 63141-2000 E-Mail: [email protected]

[email protected]

ATTACHMENT 1 TO CASE NO. U-18239 (Continued)

sl0417-1-230 Page 2 of 3

Counsel for the Residential Customer Group

Don L. Keskey, Esq. Brian W. Coyer, Esq. Public Law Resource Center PLLC 333 Albert Avenue, Suite 425 East Lansing, MI 48823 E-Mail: [email protected] bwcoyer@ publiclawresourcecenter.com

Counsel for Energy Michigan, Inc., Calpine Energy Solutions, LLC, the Michigan Chemistry Council

Timothy J. Lundgren, Esq. Laura A. Chappelle, Esq. Toni L. Newell, Esq. Varnum, LLP The Victor Center, Suite 910 201 North Washington Square Lansing, MI 48933 E-Mail: [email protected]

[email protected] [email protected]

Counsel for Wolverine Power Supply Cooperative, Inc.

Richard J. Aaron, Esq. Courtney F. Kissel, Esq. Dykema Gossett, PLLC 201 Townsend Street, Suite 900 Lansing, MI 48933 E-Mail: [email protected]

[email protected]

Counsel for Constellation NewEnergy, Inc.

Jennifer U. Heston, Esq. The Victor Center, Suite 910 124 West Allegan, Suite 1000 Lansing, MI 48933 E-Mail: [email protected]

Counsel for the Michigan Municipal Electric Association

Nolan J. Moody, Esq. Peter H. Ellsworth, Esq. Dickinson Wright PLLC 215 South Washington Square, Suite 200 Lansing, MI 48933 E-Mail: [email protected]

[email protected]

Jim B. Weeks, Esq. 809 Centennial Way Lansing, MI 48917 E-Mail: [email protected]

Counsel for the Michigan State Utility Workers Council, Utility Workers Union of America, AFL-CIO

John R. Canzano, Esq. Patrick J. Rorai, Esq. McKnight, Canzano, Smith, Radtke & Brault, P.C. 423 North Main Street, Suite 200 Royal Oak, MI 48067 E-Mail: [email protected]

[email protected]

Counsel for Spartan Renewable Energy, Inc.

Jason T. Hanselman, Esq. Dykema Gossett, PLLC 201 Townsend Street, Suite 900 Lansing, MI 48933 E-Mail: [email protected]

Counsel for The Kroger Company

Kurt J. Boehm, Esq. Jody Kyler Cohn, Esq. Boehm, Kurtz & Lowry 36 East Seventh Street, Suite 1510 Cincinnati, Ohio 45202 E-Mail: [email protected]

[email protected]

ATTACHMENT 1 TO CASE NO. U-18239 (Continued)

sl0417-1-230 Page 3 of 3

Consultant for The Kroger Company

Kevin Higgins Energy Strategies, LLC Parkside Towers 215 South State Street, Suite 200 Salt Lake City, UT 84111 E-Mail: [email protected]

re: case no. u-18239 – in the matter, on the commission’s

Documents