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

MICHIGAN OFFICE OF ADMINISTRATIVE HEARINGS AND RULES

FOR THE MICHIGAN PUBLIC SERVICE COMMISSION

* * * * *

In the matter of the application of ) Consumers Energy Company for approval ) of a power supply cost recovery plan and ) Case No. U-18402 for authorization of monthly power supply ) cost recovery factors for the year 2018. )

NOTICE OF PROPOSAL FOR DECISION

The attached Proposal for Decision is being issued and served on all parties of

record in the above matter on August 13, 2019.

Exceptions, if any, must be filed with the Michigan Public Service Commission,

7109 West Saginaw, Lansing, Michigan 48917, and served on all other parties of record

on or before August 29, 2019, or within such further period as may be authorized for filing

exceptions. If exceptions are filed, replies thereto may be filed on or before September 9,

2019.

At the expiration of the period for filing exceptions, an Order of the Commission

will be issued in conformity with the attached Proposal for Decision and will become

effective unless exceptions are filed seasonably or unless the Proposal for Decision is

reviewed by action of the Commission. To be seasonably filed, exceptions must reach

the Commission on or before the date they are due.

MICHIGAN OFFICE OF ADMINISTRATIVE HEARINGS AND RULES For the Michigan Public Service Commission

_____________________________________ August 13, 2019 Jonathan F. Thoits Lansing, Michigan Administrative Law Judge

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

MICHIGAN OFFICE OF ADMINISTRATIVE HEARINGS AND RULES

FOR THE MICHIGAN PUBLIC SERVICE COMMISSION

* * * * *

In the matter of the application of ) Consumers Energy Company for approval ) of a power supply cost recovery plan and ) Case No. U-18402 for authorization of monthly power supply ) cost recovery factors for the year 2018. )

PROPOSAL FOR DECISION

I.

PROCEDURAL HISTORY

On September 29, 2017, Consumers Energy Company (Company) filed an

application with the Michigan Public Service Commission pursuant to MCL 460.6j, 1982

PA 304 (Act 304), for approval of its proposed 2018 Power Supply Cost Recovery (PSCR)

plan and monthly PSCR Factors for the 12-month period January through December

2018. The Company seeks approval to apply, for each month in calendar year 2018, a

uniform maximum PSCR Factor of $0.00088 per kWh for all classes of customers. In

addition, the Company submitted for the Commission’s review a 5-year forecast of

projected power supply requirements of the Company’s customers, along with the

sources and costs of supply to meet the same.

U-18402 Page 2

Pursuant to due notice, a pre-hearing conference was conducted before ALJ

Dennis Mack on November 30, 2017.1 The Company and Commission Staff appeared at

that proceeding, the Attorney General intervened by right, and intervention was granted

to the Midland Cogeneration Venture Limited Partnership, Association of Businesses

Advocating Tariff Equity (ABATE), Residential Customer Group (RCG) and Great Lakes

Renewable Energy Association (GLREA), Michigan Power Limited Partnership and Ada

Cogeneration Limited Partnership, and Michigan Environmental Council and Sierra Club

(MEC/SC).2

Based on the schedule established during the pre-hearing conference, the hearing

was held on June 7, 2018. During the hearing the Company entered the testimony of its

employees:

1. Daniel Alfred, Senior Business Support Consultant II in the Transmission and Regulatory Strategies Department of Energy Supply Operations, (Direct and Rebuttal);

2. Eugene MJA Breuring, Senior Rate Analyst II in the Planning, Budgeting & Analysis Section of the Rates & Regulation and Quality Department (Direct);

3. Jim Chilson II, P.E., Fuels Transportation & Planning Director in the Energy Supply Operations Department (Direct);

4. Joshua W. Hahn, Senior Engineer in the Merchant Operations and Resource Planning Section of the Electric Grid Integration Department (Direct);

5. Theresa E. Hatcher, Director of Renewable Energy in the Transactions and Wholesale Settlements Section of the Electric Supply Department (Rebuttal);

6. David B. Kehoe, Executive Director Energy Resources Business Services (Direct);

1 1 Tr 3. Pursuant to an Order of Reassignment dated May 23, 2018, this case was reassigned from ALJ Mack to this ALJ. 2 1 Tr 6.

U-18402 Page 3

7. Stephen J. Nedeau, Senior Engineering Technical Analyst in the Electric Sourcing and Resource Planning Section of the Energy Supply Operations Department (Confidential Rebuttal);

8. Angela K. Rissman, Manager of Coal Procurement in Fossil Fuel Supply. (Confidential Rebuttal);

9. Keith G. Troyer, Senior Engineer in the Transactions and Wholesale Settlements, Electric Contract Strategy Section of the Energy Supply Operations Department (Direct and Rebuttal);

10. Andrew G. Volansky, Senior Rate Analyst II in the Revenue Requirement and Analysis Section of the Rates and Regulation Department (Direct and Rebuttal).

Through these witnesses, the Company entered Exhibits A-1 through A-23, and A-25

through A-27.3

Staff entered the direct testimony of Raushawn D. Bodiford, an engineer in the Act

304 and Sales Forecasting Section (Act 304), and Ronald J. Ancona, Manager of the Act

304 and Sales Forecasting Section within the Energy Operations Division, and Exhibit S-

1.

The Attorney General entered the direct testimony of Sebastian Coppola, an

independent business consultant, and Exhibits AG-1 through AG-15.

The RCG entered the testimony of William A. Peloquin, a retired Certified Public

Accountant, with extensive experience in utility regulation, and Exhibits RCG-1 through

RCG-10.

3 Certain of the Company’s testimony and exhibits, along with testimony and exhibits entered by the Attorney General, are deemed confidential and subject to a Protective Order entered on April 18, 2018.

U-18402 Page 4

The GLREA entered the testimony of Geoffrey C. Crandall, VP of MSB Energy

Associates, and Exhibits GLREA-1 through GLREA-13.

The other parties did not offer any evidence, and all the parties waived their right

to cross-examination.4

On March 1, 2019, the Company filed, and on March 4, 2019, the Company re-

filed its Motion To Require Substantiation Regarding Representation, Substitution of

Counsel, or Revocation of Intervention. After RCG filed various responsive pleadings, the

Company withdrew its motion.

The evidentiary record is contained in 309 pages of transcript and 65 exhibits. The

Company, Staff, the Attorney General, RCG and GLREA filed initial briefs on July 20,

2018, and reply briefs on August 31, 2018.5

II.

STATUTORY REQUIREMENTS

Public Act 304 of 1982 (Act 304), among other things, governs PSCR clauses,

annual PSCR plan cases, and annual PSCR reconciliation cases for electrical utilities.

Specifically, Act 304 provides for a PSCR clause that “permits the monthly adjustment of

rates for power supply to allow the utility to recover the booked costs, including

transportation costs, reclamation costs, and disposal and reprocessing costs, of fuel

burned by the utility for electric generation and the booked costs of purchased and net

interchanged power transactions by the utility, incurred under reasonable and prudent

policies and practices.” MCL 460.6j(1)(a).

4 2 Tr 18-19. 5 The Company filed a redacted and confidential version of its Initial Brief and its Reply Brief. The Attorney General filed a redacted and confidential version of its Initial Brief.

U-18402 Page 5

Subsection 6j(3) of Act 304 requires a utility with a PSCR clause to annually file a

complete PSCR plan describing the expected sources of electric power supply and the

changes in the cost of power supply anticipated over a future 12-month period. Based on

this information, the utility is to request specific PSCR factors for each of the 12 months

covered by its PSCR plan. The PSCR plan must also describe all major contracts and

power supply arrangements for the 12-month period.

Subsection 6j(4) of Act 304 requires the utility to file--contemporaneously with the

submission of its PSCR plan--a five-year forecast of its power supply requirements, its

anticipated sources of supply, and its projections of power supply costs, all in light of its

existing sources of electrical generation and sources of electric generation under

construction.

Subsection 6j(5) of Act 304 provides that, after a utility files its PSCR plan and five-

year forecast, the Commission is to conduct a proceeding to review the reasonableness

and prudence of the PSCR plan and to establish PSCR factors for the period covered by

the plan.

Subsection 6j(6) of Act 304 provides that, in its final order in a PSCR plan case,

the Commission shall evaluate the reasonableness and prudence of the decisions

underlying the utility’s plan, and shall approve, disapprove, or amend the plan

accordingly. In evaluating the decisions underlying the utility’s plan, the Commission shall

consider the cost and availability of the electrical generation open to use by the utility; the

cost of available short-term firm purchases; the availability of interruptible service; the

ability of the utility to reduce or eliminate any firm sales to out-of-state customers (if the

utility is not a multi-state utility whose firm sales are subject to other regulatory authority);

U-18402 Page 6

whether the utility has taken all appropriate steps to minimize the cost of fuel; and other

relevant factors. In its final order, the Commission must approve, reject, or amend the 12

monthly PSCR factors requested by the utility, which factors shall not reflect any items

that the Commission could reasonably anticipate would be disallowed under Subsection

6j(13), which sets forth the criteria to be considered in a subsequent PSCR reconciliation

concerning the 12-month period covered by the plan in question.

Subsection 6j(7) of Act 304 provides that the Commission must evaluate the

decisions underlying the 5-year forecast filed by a utility. The Commission may also

indicate any cost items in the 5-year forecast that, on the basis of present evidence, the

Commission would be unlikely to permit the utility to recover from its customers in rates,

rate schedules, or power supply cost recovery factors established in the future. This is

colloquially known as a “Section 7 warning”.

III.

THE 2018 PSCR PLAN AND 5-YEAR FORECAST

A. PSCR Plan

Mr. Volansky testified that the Company calculated of the 2018 PSCR Factor by

adding the System Power Supply costs of $1.6 billion, Net Transmission expenses of

$408.6 million, and Total Environmental costs of $14.6 million to set the Total System

Power Supply costs of $2,015,050,920.6 That amount is then divided by the Total System

Energy Requirements, 35,650,621,000 kWh, to arrive at the Average Cost per kWh of

$0.05652, from which quotient the Base Recovery Factor, $0.05570, is subtracted to

6 2 Tr 165-166; Exhibit A-23.

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calculate the Remaining Cost per kWh: $0.00082.7 The final step is multiplying the Base

Recovery Factor by the Line and Transformation Loss Factor of 1.079 to set the maximum

PSCR Factor: $0.00088 per kWh.8

The components of the foregoing calculation were provided by various Company

witnesses. Mr. Hahn testified the 2018 System Power Supply costs projection depicted in

Exhibit A-12 were derived from the PROMOD IV Production Costing Program, an

economic dispatch computer program which uses “up-to-date assumptions and data”,

and with the results having been “reviewed for reasonableness and for consistency with

input and assumptions.”9 Mr. Hahn testified that the PROMOD IV “simulates the dispatch

of the Company's generating resources and P&I power resources to meet projected

customer electric demand requirements”, and that “[t]he model used by PROMOD IV is

structured to align as closely as possible with the way that the MISO operates and

administers the Midwest Energy Market”.10

Mr. Hahn testified that the Company changed its presentation of fuel and

purchased and net interchange power and expenses for this 2018 Plan. In order to comply

with Section 6w(3) of Act 341 and meet the filing requirements as set forth in MPSC Case

No. U-18239, power supply costs have been identified for both capacity-related (or

“fixed”) costs and energy-related (or “variable”) costs.11 Mr. Hahn testified that Exhibit A-

12 includes data supplied by Mr. Chilson, Mr. Breuring and Mr. Kehoe.12

7 Id. 8 Id. 9 2 Tr 74. 10 2 Tr 77. 11 2 Tr 73-74. 12 2 Tr 77, 78.

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System Transmission costs were testified to by Mr. Alfred, which included “all of

the charges imposed on the Company under MISO’s Open Access Transmission, Energy,

and Operating Reserve Markets Tariff which is filed and approved by FERC.”13. Mr. Alfred

also described the various components of the charges, including $413,115,958 total

transmission and energy market administrative expense and a projected $4,500,000

reactive revenue requirement credit.14 Mr. Alfred noted the steps the Company has

undertaken to reduce transmission costs, such as participating in a stakeholder process

for transmission planning and project approval, and monitoring and intervening in MISO

and transmission owners’ tariff filings.15

The final component of the projected Total System Power Supply costs are

environmental costs for UREA, aqueous ammonia, lime, and activated carbon.16 The

purpose for using these compounds, along with the basis for the projected costs, were

provided by Mr. Kehoe.17

The Company also proposes and seeks approval of purchases of additional

capacity to meet its capacity planning reserve margin target for the 2018 MISO Planning

Year. Mr. Troyer testified that, as a Load Serving Entity (“LSE”), the Company is required

to ensure it has sufficient capacity to provide adequate electric supply as determined by

MISO.18 Generally, the capacity planning reserve margin target is designed to include

consideration of demand forecast variances, generator forced outages and derates, and

13 2 Tr 24; Exhibit A-1 14 2 Tr 30. 15 2 Tr 31. 16 Exhibit A-23. 17 2 Tr 107-110; Exhibits A-17, A-18, A-19, and A-20. 18 2 Tr 132.

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transmission import limitations.19 Mr. Troyer testified to how the Company determines the

capacity reserve margin target:

The Company relies on MISO to determine the appropriate capacity planning reserve margin that Consumers Energy should maintain. For PY 2017, the MISO Loss of Load Expectation (“LOLE”) Working Group performed a LOLE study which considered the probability that various amounts of generation resources would be inadequate to serve firm demand in the MISO footprint. Upon determining the amount of generation resources that would be necessary to achieve a LOLE of less than one occasion every ten years, a reserve margin (expressed as a percentage of peak firm demand) is calculated and assigned to all LSEs.

. . . .

For PY 2017, MISO Staff with consultation by the LOLE Working Group determined that, using capacity discounted for forced outages, a capacity planning reserve margin target (or “unforced” capacity planning reserve margin target) for MISO of at least 7.8% of the Company’s demand at the time of MISO’s coincident peak demand was sufficient to satisfy ReliabilityFirst Corporation’s (“RF”) capacity planning criteria of expecting to interrupt firm load no more frequently than one occasion in ten years. For PY 2018, MISO Staff with consultation by the LOLE Working Group determined that, using capacity discounted for forced outages, a capacity planning reserve margin target for MISO of at least 8.4% of each LSE’s demand at the time of MISO’s coincident peak demand was sufficient to satisfy RF’s capacity planning criteria. . . . On September 12, 2017, MISO’s LOLE Working Group projected planning reserve margin targets of 8.4% for PY 2018, 8.3% for PY 2021, and 8.4% for PY 2023. The Company has extrapolated these values and rounded to the nearest tenth of a percent to project a planning reserve margin target of 8.4% for PY 2019, 8.3% for PY 2020, and 8.4% for PY 2022, as shown on line 3 of Exhibit A-21.20

Mr Troyer adds that the Company is required to comply with the appropriate

unforced capacity reserve margin requirement by having Zonal Resource Credits

(“ZRC’s”) equal to annual firm peak demand at the time of MISO’s coincident peak

demand.21 This amount of capacity provides an adequate reserve to cover load forecast

19 Id. 20 2 Tr 132-133.21 2 Tr 134.

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error, weather variability, and transmission contingencies while considering the benefits

that result from demand diversity over the MISO footprint.22

Based on the foregoing, the Company seeks approval of its 2018 PSCR Plan and

authority to set it its PSCR Factor at $0.00088 per kWh.23

B. Five-Year Forecast

Consistent with MCL 460.6j(4), the Company filed its forecast for its power supply

requirements and costs, along with arrangements to meet those requirements, for the

period of 2018-2022. The Company’s five-year forecast describes the power supply

requirements of the Company’s customers, the Company’s anticipated sources of supply,

and projections of power supply costs during the time period.24 The five-year forecast also

describes all relevant major contracts and power supply arrangements entered into or

contemplated by the Company.25

Mr. Breuring provided detailed testimony regarding these variables, along with the

methodology used to arrive at the forecasts.26 The Company also provided a forecast of

deliveries, broken down by customer class, for the five-year period, together with

projected generation requirements and peak demand.27

Mr. Troyer testified concerning the electric generation resources upon which the

Company expects to rely throughout the five-year forecast period.28 Mr. Hahn testified

about the major Power Purchase Agreements (“PPAs”) between the Company and Non-

22 Id. 23 Exhibit A-23. 24 Company Initial Brief, p. 2. 25 Id.26 2 Tr 40-46. 27 Exhibits A-2 through A-6. 28 2 Tr 132-152; Exhibit A-21.

U-18402 Page 11

Utility Generators (“NUGs”).29 Mr. Hahn also testified concerning the Company’s estimate

of power supply costs for the forecast period, based on dispatch models of the volume of

generation and purchases expected to be economic.30 Mr. Alfred testified concerning the

costs of transmitting the energy required to serve the Company’s forecast load during the

forecast period, as well as other market and administrative costs imposed by FERC.31 Mr.

Kehoe testified concerning environmental allowances and expenses during the forecast

period.32

Based on the foregoing, the Company seeks a determination that none of the

projected costs in its 5-year forecast warrant a Section 7 warning. MCL 460.6j(7).

IV.

POSITIONS OF THE PARTIES ON THE 2017 PSCR PLAN & 5-YEAR FORECAST

A. Staff

Staff is recommending that all requests sought by the Company in this case be

granted, and that the PSCR factors Consumers has requested be approved.33 Staff

further recommends that the Company reflect the PSCR impacts of the Tax Cut and Jobs

Act of 2017 (“TCJA”) as soon as practicable, consistent with Commission directives.34

Mr. Ancona testified that Staff reviewed the Company’s filing to assess the

reasonableness and prudence of the plan.35 Mr. Ancona indicated that Staff’s review

29 2 Tr 80-82; Exhibit A-14. 30 2 Tr 73-84; Exhibit A-13. 31 2 Tr 24-32; Exhibit A-1. 32 2 Tr 105-110; Exhibits A-17, A-18, A-19, and A-20. 33 2 Tr 192; Staff Initial Brief p. 4. 34 2 Tr 192. 35 2 Tr 189.

U-18402 Page 12

found Consumers’ plan did not introduce any new issues, and is consistent with past

Commission approvals.36 Mr. Ancona added that the Company’s plan assumes utilization

of existing internal resources and that the projections that produce the factors provide a

reasonable representation of future events.37 Staff also determined that there were no

known costs that would be approved for future cost recovery at this time.38

B. Attorney General

The Attorney General raises three issues in this case. First, the Attorney General

argues that the Commission should issue a section 7 warning that some portion of the

Company’s coal supply cost could be disallowed during the reconciliation phase of the

PSCR cases in 2018 and 2019 because the Company did not choose the lowest cost

bids for certain coal supply contracts.39 Mr. Coppola testified that the Company’s decision

to incur $2,882,880 of additional coal costs for 2018 and $112,320 for 2019 is neither

reasonable nor prudent, and that the Company’s reasons to enter into coal purchase

contracts that will increase the cost of power recoverable through the PSCR factor are

not justified or acceptable.40

The Attorney General also asserts that the Commission should ensure that the

Company revises its PSCR factor during 2018 to pass along to customers any savings it

receives from its transmission services provider as a result of the lower corporate tax rate

under the TCJA.41 Mr. Coppola testified that for 2018 and future years, the Company has

36 2 Tr 190. 37 Id. 38 Staff Initial Brief, p. 4. 39 Attorney General Initial Brief, p. 2 40 2 Tr 205. 41 Attorney General Initial Brief, p. 13.

U-18402 Page 13

projected transmission costs based on provider rates which reflect the prior 35% tax

rate.42 Mr. Coppola argues that the PSCR factor for 2018 reflects higher transmission

costs than are likely to occur during the year due to expected refunds and rate

adjustments to be made by the transmission provider.43

Finally, the Attorney General argues that the Commission should direct the

Company to take steps to reduce any excess surplus capacity for 2019, 2020 and 2021.44

Mr. Coppola testified that the amount of excess capacity that is anticipated in 2019 and

2020 is excessive and adds millions of dollars to power costs recoverable through the

PSCR and base rates.45

C. GLREA

GLREA raises two issues. First, GLREA asserts that the Company’s proposed

PSCR forecast and five-year plan are flawed because the PSCR is devoid of residential,

commercial and industrial customer-owned solar photovoltaic (PV) energy resources in

its 2018-2022 PSCR resource mix.46 Mr. Crandall testified that the growth in the

Company’s customer-owned renewable energy resources has not been included in the

Company’s forecast for the plan period.47 He adds that while the Company’s plan includes

renewable energy that is Company owned or purchased through PPAs, customer-owned

renewable generation is not considered in the Company’s PSCR load forecasts.48

42 2 Tr 206. 43 2 Tr 207 44 Attorney General Initial Brief, p. 2. 45 2 Tr 212. 46 GLREA Initial Brief p. 1. 47 2 Tr 244. 48 2 Tr 245, 246.

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GLREA also argues that the Commission should coordinate resource planning

under Act 304, Act 295, and Act 342 in a complementary manner.49 Mr. Crandall argues

that the Company should have provided an analysis in support of its PSCR plan that

included analyses and discussion of their in-depth review of strategies and planning

assessments of solar capacity and energy for the five-year forecast and plan.50 He adds

that approval of the Company’s plan would adversely impact Michigan ratepayers, as

dollars leaving the state for more expensive fuel and purchase power acquisition when a

renewable fueled generation option exists would result in an economic drain on

businesses and the citizens doing business in or residing in Michigan.51

D. RCG

RCG also raises two issues in this case. Like the Attorney General, RCG argues

that the Company’s plan and five-year forecast does not adequately reflect the impact of

the TCJA, which will reduce the cost of purchasing and transporting electricity and natural

gas for the ratepayers.52 Thus, the Commission should require Consumer's to

demonstrate that it is acting as a fiduciary for the ratepayers in obtaining TCJA cost

reductions for electricity and natural gas.53

RCG also argues that the Company should continue to include lease costs for the

Zeeland plant interconnection pipeline, thereby foregoing the cost savings that would

result from the Company’s purchase of the pipeline.54

49 GLREA Initial Brief p. 5. 50 2 Tr 252. 51 2 Tr 254. 52 RCG Initial Brief, p. 1. 53 2 Tr 235. 54 Id.

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V.

ANALYSIS55

A. Coal Supply Contracts

The Attorney General asserts that the Company’s decisions to accept higher cost

bids for coal under coal supply contracts #193 and #279 were neither reasonable nor

prudent, and thus, recommends that the Commission issue a Section 7 warning to the

Company for these coal supply contracts that it is likely that a portion of those coal

purchase costs may be disallowed in the reconciliation phase of the PSCR case.56

Contract #193

The Attorney General takes issue with the Company’s failure to choose the lowest

cost bid for this coal contract. The Company received bids for this contract to

supply coal for a three-year period from 2016 to 2018, and selected Bid #4 from

from the mine.57 The 2018 price is per ton

or per Million Btu (MMBtu).58 also provided an alternative bid from

55 At the outset, it should be noted that Staff and Attorney General apparently disagree regarding the applicable burden of proof. Staff asserts that “[s]ince a PSCR factor can be self-implemented, a PSCR plan is afforded prima facie, ‘just and reasonable’ status until the Commission determines otherwise.” Staff Initial Brief, p. 3. Staff adds that “[t]he standard for approving a billing factor that does not establish cost recovery, and whose resulting revenue will be trued up against actual costs, is lower than that which does result in ultimate cost recovery.” Id. The Attorney General asserts that the Company has the burden of proving “by a preponderance of evidence” that the Company’s proposed PSCR costs were “incurred under reasonable and prudent policies and practices”. Attorney General Reply Brief, p. 3-4. The Attorney General’s position is consistent with prior Commission’s holdings. See, e.g., In the Matter of the Application of Consumers Energy Company, U-17678-R, Order, February 5, 2018, p. 13 (“Under Act 304, Consumers has the burden of proof to establish that its decisions were reasonable and prudent.”); In the Matter of the Detroit Edison Company for the Reconciliation of Power Supply Costs, U-16434-R, Order, June 30, 2015, p. 9 (“Detroit Edison must demonstrate by a preponderance of the evidence, the expenses were a result of reasonable and prudent management actions.”)56 The Attorney General initially also challenged the bid the Company accepted for coal contract no. 278, but later dropped that challenge as it subsequently learned that the Company had chosen the lower cost bid for that contract. Attorney General Initial Brief, p. 10, fn 10; Company Reply Brief, p. 15. 57 2 Tr 202. 58 Id.

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labeled as Bid #1 .59 Mr. Coppola asserts that Bid #1 had a

lower price per ton of for 2018, or per MMBtu, a lower Btu content and

a lower sulfur content compared to Bid #4.60 Mr. Coppola argues that Bid #1’s lower Btu

content is reflected in the cost per MMBtu, which is lower than the accepted Bid #4.61 Mr.

Coppola argues that Bid #1 would have resulted in lower purchase cost of

in comparison to Bid #4 at , a savings of approximately for

2018.62 Moreover, the “cumulative impact” of the price differential over the three-year

period of 2016 to 2018 is approximately 63

Mr. Coppola adds that the reasoning offered by the Company for deciding not to

accept Bid #1 – that the coal under Bid #1 had not been previously offered, tested or

purchased, and the Company would not commit to purchase a significant volume of new

specification coal until a test burn of the coal had been conducted to demonstrate that the

coal is acceptable for use - was problematic in three respects.64 First, Mr. Coppola stated

that

65

Second, while the coal for Bid #1 had a slightly lower Btu content, it also had much lower

sulfur content, which would reduce emission treatment and cost.66 Third, and most

importantly, as the Company issues requests for supplier bids well ahead of when the

59 Id. 60 Id.61 Id. 62 Id. 63 Id. 64 Id. 65 2 Tr 203. 66 Id.

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coal deliveries are needed, it “would seem logical and reasonable to expect the Company

to allow sufficient time to perform any necessary coal burning tests”.67 In that regard, the

Attorney General notes that the Company currently burns coal that at some point was

“new specification”, and yet it managed to somehow acquire the coal, do test burns and

approve it for use presumably using the same procedures it now asserts prevented it from

using the Bid #1 coal.68 and indeed, that the Company eventually approved and used

lower heating value coal with no operational difficulties.69

Ms. Rissman counters that Mr. Coppola’s conclusion “assumes that this purchase

decision can be made by exclusively using $/ton.”70 Ms. Rissman asserts that Mr.

Coppola’s calculation “fails to capture the difference in heating value between the two

coals”, such that to obtain the same total heating value for Bid #1, an additional

tons MMBtu) would need to be purchased and delivered.”71 Ms. Rissman

points out that, “[t]hough the Company did pay more for Bid #4, it also received a higher

heating value because Bid #4 had a heating value of 8,800 Btu/lb., while Bid #1 had a

Btu content of only 8,600 Btu/lb.” She concludes that Confidential Exhibit A-27 shows that

the actual difference between these bids was in 2018, even if the Company

had been able to make the purchase without the benefit of a test burn.”72

67 2 Tr 282. 68 Attorney General Initial Brief, p. 10, citing Exhibit AG-8 and Confidential Exhibit AG-9.69 Id. 70 2 Tr 269. 71 Id. Emphasis in original.72 Id.

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Regarding Mr. Coppola’s other concerns, Ms. Rissman asserts that it would be

“extremely risky” for this large of a purchase for the Company “to blindly assume” the

combustion characteristics of a new 8,600 Btu/lb. coal would be materially the same as

the 8,800 Btu/lb. coal without the benefit of a detailed review and a test burn.73 She points

out that

74 Finally, Ms. Rissman adds that it is

important for the Company to conduct a test burn in order to “observe the combustion”

and otherwise “validate that the new product can be consumed without adverse

operational and emissions concerns.”75

Regarding Mr. Coppola’s assertion that the Company should have allowed

sufficient time to conduct any test burns, Ms. Rissman testified that the coal procurement

process, which includes the time to issue a solicitation, receive and evaluate bids, select

a winning bid, and notify the supplier, transpires over a short time period, which typically

only allows the Company approximately seven days to evaluate each offer.76 Conversely,

the process to test a product, which typically involves the purchase, delivery, burning, and

analysis of the product at the Company’s plants, can take months to complete.77 As a

result, the Company did not have sufficient time to perform the necessary tests to evaluate

73 2 Tr 269-270.74 2 Tr 270. 75 2 Tr 270-271. 76 2 Tr 123. 77 Company Reply Brief, p. 6-7.

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the coal in Bid #1 in order “to have confidence this purchase would not have any negative

operational impacts at any of our plants.”78

Regarding the Attorney General’s contention that the Company is currently using

“new specification” coal for which the Company managed to do test burns and approve it

for use, the Company responds as follows:

The Company’s evaluation of Contract #193 was completed in October 2015. The purchase of coal under Contract #193 was significant, with 936,000 tons in 2016, and approximately 1.5 million tons in both 2017 and 2018. Prior to that evaluation, Consumers Energy had not entered into any contracts to purchase coal from the same mine with a BTU specification of 8,600. Subsequently, the Company purchased 8,600 BTU coal from the referenced mine only “after the Company performed testing for an 8,600 BTU product and started burning small volumes of 8,600 BTU coal without experiencing operational issues.” Although the Attorney General criticizes the Company for not “taking the steps necessary to properly vet the coal available through Bid #1 for use in its plant(s)”, the Company in fact tested the 8,600 BTU coal throughout 2015, and approved procurement of this specification of coal in January 2016. However, the verification of the 8,600 BTU coal was not accomplished prior to the Company completing its evaluation of Contract #193, and thus the Company reasonably chose not to select Bid #1.79

Regarding Mr. Coppola’s argument that there would have been emission treatment

and cost advantages to the lower sulfur content for the Bid #1 coal, Ms. Rissman asserts

that the sulfur content for Bid #1 and Bid #4 were both below the defined quality

specification and, as such, “did not have a material economic impact on the decision-

making process.”80

78 2 Tr 270.79 Company Reply Brief, p. 6-7. Emphasis in original. 80 2 Tr 271.

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Contract #279

The Attorney General similarly takes issue with the Company’s failure to choose

the lowest cost bid for this coal contract for coal to be delivered in 2019. According to Mr.

Coppola, the Company selected Bid #2 with a price per ton of or per

MMBtu, instead of Bid #1 with a price of per ton or per MMBtu.81 As

such, Mr. Coppola asserts that the Company chose the bid which is more than

the other available bid.82 Mr. Coppola adds that the quality of the coal for the two bids is

comparable such that there is “no apparent quality of coal distinction” to accept the higher

cost bid, and thus the Company’s decision to accept the higher cost bid is neither

reasonable nor prudent.83 The Attorney General argues that the Company’s reasoning

for choosing the bid it did – that the bid included sulfur specification flexibility companion

benefits – is not compelling as the Company had not exercised the option to take

advantage of this benefit and the benefit is only valued at 84

Ms. Rissman counters that the Company’s selection of Bid #2 was reasonable as,

while the Company paid a “slight premium” for Bid #2, in exchange the Company received

"sulfur flexibility companion benefits”:

At the time of this purchase, one of the Company’s generating plants was experiencing operational issues that could be lessened by receiving coal with lower sulfur content. The contract for Bid #2 is for coal with lower sulfur content, but has a built-in provision to revert to the same sulfur specification and price as Bid #1 if the Company does not have a need to exercise this option.85

81 2 Tr 203-204. 82 2 Tr 205. 83 2 Tr 204, 205. 84 Exhibit AG-11. 85 2 Tr 272.

U-18402 Page 21

Ms. Rissman also points out that Mr. Coppola’s testimony includes two errors

regarding applicable values, including for the price per MMBtu for Bid #1.86

As a general matter, Staff disagrees with the Attorney General’s claim that the

Company has failed to demonstrate the reasonableness and prudence of its coal

purchasing strategy, finding that the Attorney General’s concept of what the Company’s

purchasing strategy should be “is overly narrow and disregards many of the other factors

that are considered when making decisions on coal purchases.”87 Staff argues that, given

the Company’s response to the AG’s concerns, it is clear that the Company “considers

the bidding process as part of a larger purchasing strategy that also incorporates

operational and logistical considerations”.88 Therefore, Staff asserts that the Company

adequately demonstrated its coal supply contract purchasing is part of a larger purchasing

strategy.89

This PFD finds that the evidence presented supports a finding that the Company

has made reasonable and prudent decisions on these two coal supply contracts. The

Company has offered reasonable explanations for why it chose to accept the bids that it

did, and why it was prudent to do so despite the bids being of a higher cost. Indeed, the

record indicates that the Company takes into consideration several other factors besides

the relative price of the coal in making its determinations of what coal to purchase. The

Company’s testimony that it did not have time to adequately evaluate the new and

different coal offered under the alternative bid (Contract #193) and that it received better

86 Id.87 Staff Reply Brief, p. 2. 88 Id. 89 Id.

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sulfur content and flexibility through contract options (Contract #279) are persuasive.

Indeed, the Company’s evidence adequately answered the somewhat speculative

assertions raised by the Attorney General. Moreover, as Staff points out, the Attorney

General’s concerns are “overly narrow”, based on a singular focus on cost rather than

other applicable factors such as “operational and logistical considerations”. For these

reasons, the recommendations of the Attorney General that Section 7 warning be issued

as to the costs associated with these two contracts should be rejected by the Commission.

B. TCJA

The Attorney General notes that the Company uses power transmission services

provided by Michigan Electric Transmission Company, LLC (“METC”) and that the

Company has projected transmission costs in this PSCR case based on METC rates

which reflect the 35% tax rate for 2018 and future years.90 Mr. Coppola testified that the

lower tax rates will result in lower transmission services costs for 2018 and that the

Company should be required to adjust the PSCR factor during 2018 as soon as it has

received information from METC regarding any refunds it is due and the lower

transmission rates it will be charged.91 The Attorney General asserts that the transmission

cost should be lower by approximately $17.3 million from the levels forecasted by the

Company due to the lower federal tax rated applied to METC.92 The lower transmission

costs provided by the Company in discovery response AG-CE-109 (Exhibit AG-4) will

90 Attorney General Initial Brief, p. 13. 91 2 Tr 207-208 92 Exhibit AG-4.

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lower its PSCR factor for 2018 by approximately 59% from $0.00088 to $0.00036 per

kWh.93

The Staff agrees that the Commission should instruct the Company to adjust the

PSCR factor to reflect the impacts of the TCJA during 2018 “as soon as practicable,”

noting that the PSCR factor “should pass-through during 2018 to avoid a large over-

recovery of PSCR costs at year-end.”94 Similarly, the RCG recommends that the

Commission require the Company to present a complete analysis and discussion “to

determine reductions in Act 304 costs to account for supplier cost reductions resulting

from the TCJA”.95

The Company counters that Mr. Coppola’s concerns have been completely

addressed by the Company and that no further actions by the Commission are

necessary.96 Mr. Alfred explained that pursuant to FERC’s approval of mid-year rate

updates, METC implemented lower transmission rates in its March 2018 settlements

which were billed to the Company.97 Mr. Alfred explained that this “effectively

implemented the lower federal tax rate into all METC Transmission settlements on a go-

forward basis starting with March, 2018.”98 Mr. Alfred further clarified that, since the

months of January and February 2018 were not billed at the lower transmission rates, “re-

settlements” were required to reflect the lower transmission rates, which occurred in May

2018 as a reduction to transmission bills.99

93 Exhibit AG-5 94 Staff Reply Brief, p. 2-3. 95 RCG Initial Brief, p. 2. 96 Company Initial Brief, p. 18. 97 2 Tr 35. 98 Id. 99 Id.

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In addition, Mr. Volansky explained that PSCR cost reductions related to the TCJA

are captured in the Company’s monthly PSCR reconciliations:

“Every month, actual PSCR revenues and costs are entered into a reconciliation, and any corresponding over/under recovery is recorded. The impact from Transmission rates billed using the higher tax rates in January and February and the corresponding re-settlements that occurred in May, as discussed in the direct testimony of Company witness Daniel S. Alfred’s, are captured in this monthly recording of revenues and costs in the reconciliation process. The resulting over/under recovery is included in the calculation of the monthly PSCR factor that is used to adjust the base rate factor so PSCR revenues collected on forecasted sales for the remainder of the year will cover forecasted costs plus any over/under recovery.”100

This PFD finds that the bases for the Company’s opposition to the Attorney

General’s recommendation are reasonable. Mr. Volansky’s testimony - that the impact

from transmission rates are captured in the “over/under recovery” reconciliation and is

included in the calculation of the monthly PSCR factor – is persuasive. Moreover, neither

the Attorney General, Staff, nor RCG cross-examined Mr. Volansky regarding his

testimony, nor otherwise addressed his testimony in their briefs. Thus, the

recommendations that the Commission instruct the Company to adjust the PSCR factor

during 2018 are unsupported by the record.

C. Excess Capacity

The Attorney General argues that the amount of excess capacity that is anticipated

in 2019 and 2020 “is excessive and above levels that are reasonable and prudent.”101 Mr.

Coppola points out that the Company shows that the Company’s available generating

capacity exceeds the MISO Coincident Peak System Load “by 10.62% in 2018, 16.30%

100 2 Tr 169-170. 101 Attorney General Initial Brief, p. 17.

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in 2019 and 19.67% in 2020 before dropping down to around 11% in 2021 and 2022.”102

Thus, Mr. Coppola concludes that “it appears that the Company expects to have surplus

capacity in each of the five years, with large surpluses in 2019 and 2020.”103 Mr. Coppola

adds that the Company forecasted surplus capacity of 568 ZRCs for 2019 and 811 ZRCs

for 2020, with surplus ZRCs ranging from 161 to 196 in the other years of the five-year

plan.104 Mr. Coppola concluded that while some surplus capacity over the MISO required

reserve margin “is reasonable as a buffer against forecast to actual variances, the excess

capacity in 2019 and 2020 is not.”105

Mr. Coppola testified that he was able to “partially” determine the potential increase

in the cost of power from the Company’s projected surplus capacity. Specifically,

regarding the TES Filer generating plant, Mr. Coppola testified that the cost of the excess

capacity of 114 ZRCs is $16,769,286 in 2019 and $16,890,924 in 2020.106 He adds that

assuming the Company is successful in selling the excess capacity at prices estimated

by the Company, the remaining incremental costs to PSCR customers “would be

approximately $8.9 million in 2019 and about the same amount in 2020 for only the TES

Filer plant capacity, with the other excess capacity potentially adding to this cost.”107

Mr. Coppola argues that the Company mistakenly shows ZRCs from the Palisades

PPA ending early in 2020 but that the Company is indicating that that PPA will remain in

place until 2022, which further adds to the 2021 surplus capacity.108 Mr. Coppola also

102 Id. 103 Id. 104 Id, p. 16-17: Exhibit AG-2. 105 2 Tr 209. 106 2 Tr 211. 107 2 Tr 212. 108 2 Tr 210-211.

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argues that additional excess capacity is expected to be added from returning PURPA

contracts, and reductions through peak power demand programs.

Mr. Coppola asserts that it is “not reasonable to add new generating capacity at a

cost much higher than the Company can sell the surplus capacity in the MISO market”,

and thus concludes that the Company should “take steps now” to “minimize the amount

of surplus capacity that is likely to exist at least over the next three years from 2019 to

2021”, including delaying the addition of new capacity from new renewable resources,

whether Company-owned or from PPAs, and reevaluating “the pace at which it pursues

load reduction programs” over the next three years.”109

In rebuttal to the Company’s argument that capacity determinations should be

handled other than through a PSCR proceeding, the Attorney General argues that

capacity issues are appropriately addressed in PSCR cases pursuant to MCL 460.6j(4),

and that, since the Company presented capacity information as part of its filing, it is “fair

game for review and commentary”.110

The Company counters that Mr. Coppola’s recommendations were completely

refuted by the Company’s evidence, and that the Attorney General did little to respond to

the Company’s testimony.111 Indeed, the Company argues that Mr. Coppola’s

recommendations to reduce capacity from the sources of generation he identifies are not

reasonable or practicable, “cannot reduce the Company’s capacity position”, and are

contrary to Commission orders.112

109 2 Tr 212-213. 110 Attorney General Initial Brief, p. 18. 111 Company Reply brief, p. 11. 112 Company Reply brief, p. 12.

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Regarding the Filer City PPA, Mr. Troyer explained that this restructured contract

results in savings as presented in the Company’s filing in Case No. U-18392, which was

approved by the Commission in its February 5, 2018 Order in Case No. U-18392.113 Mr.

Troyer adds that this contract does not provide the Company with the discretion to

determine when the configuration is completed by Filer City.114

Regarding the Palisades PPA, in order to mitigate its surplus capacity position for

2018 to reduce or eliminate extra costs resulting from excess capacity, Mr. Troyer

explained that after the Commission’s September 22, 2017 Order in Case No. U-18250,

which continued the Palisades PPA beyond the early termination, the Company voided

contracts to purchase additional ZRC’s as part of a replacement plan for that early

termination of Palisades.115

Regarding the Company’s PURPA contracts, Mr. Troyer points out that because

the Company is obligated to buy the energy and capacity through PURPA contracts with

Qualifying Facilities (“QFs”) up to 20 MW in size, the Company does not have the ability

to choose how much capacity it acquires from QFs.116 Mr. Troyer adds that the

Commission’s February 22, 2018 Order in Case No. U-18090 directed the Company to

execute 150 MW of additional capacity through new PURPA contracts with QFs in the

PURPA queue, which the Company expects to add over the next five years.117

Regarding Mr. Coppola’s suggestion that the Company should “reevaluate the

pace at which it pursues load reduction programs”, Mr. Troyer points out that the

113 2 Tr 161. 114 2 Tr 155. 115 2 Tr 159. 116 2 Tr 156. 117 2 Tr 156-157.

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additional ZRCs related to Air Conditioning Cycling and Commercial and Industrial DR

programs and to Time of Use programs are approved through the Company’s rate case

proceedings, and that energy efficiency levels and costs for calendar years 2018 through

2021 have already been approved in the Commission’s January 23, 2018 Order in Case

No. U-18261.118

Mr. Troyer adds that Mr. Coppola’s suggestion that the Company delay the

addition of new renewable resources is misplaced, as the additional capacity from these

sources are not significant and need for these additional resources are addressed in the

Company’s renewable energy plan filed in Case No. U-18231.119

Mr. Troyer asserts that Mr. Coppola’s focus appears to be the Company’s capacity

position in years 2019 through 2022, and points out that the Company’s Plan “is only

seeking to set the appropriate pricing mechanisms for recovery of power supply costs in

2018.”120 Mr. Troyer adds that accurate capacity planning requires a long-term view of

capacity resources and customer demand, and that the “best place to address the

Company’s capacity needs” is through an IRP filing, referencing the Company’s June

2018 IRP filing in Case No. U-20165.121

Staff generally agrees with the Company on this issue, noting that some of the

intervenors’ recommendations would lead to changes to the Company’s existing

118 2 Tr 157. 119 2 Tr 160. This PFD notes that the Company’s REP was approved pursuant to the Commission’s February 7, 2019 Opinion and Order. 120 2 Tr 159-160. 121 2 Tr 160. This PFD notes that the Commission issued its Order Approving Settlement Agreement dated June 7, 2019 in that case.

U-18402 Page 29

resources, which Staff argues are “outside the scope of what the Commission can

determine in a PSCR case”:

PSCR cases review costs resulting from existing resources that have been established in or through other proceedings with the MPSC. Adding to or subtracting from existing resources will have rate impacts beyond the PSCR factor that cannot be addressed in an Act 304 proceeding.122

This PFD finds that the Company’s evidence offered in opposition to the Attorney

General’s recommendations is persuasive. As the Company asserts, much of that of

which the Attorney General complains has been addressed in other cases. Moreover, the

Attorney General did not cross-examine Mr. Troyer on rebuttal or otherwise adequately

address his testimony in their briefs. In addition, as Staff argues, capacity issues are

better addressed in IRP cases. See, MCL 460.6t(8)(a)(“The commission shall approve

the integrated resource plan under subsection (7) if the commission determines [that] the

proposed integrated resource plan represents the most reasonable and prudent means

of meeting the electric utility's energy and capacity needs.”). Thus, the Attorney General’s

recommendations - that the Commission instruct the Company to delay addition of new

capacity from renewable energy resources and reevaluate the pace at which it pursues

load reduction programs - are unsupported by the record.

Solar Resources

GLREA argues that a lower PSCR factor would likely result from the Company

reflecting the impacts of residential, commercial and industrial customer-owned solar

photovoltaic (PV) systems appropriately in its 2018-2022 PSCR plan filing.123 Mr. Crandall

122 Staff Initial Brief, p. 4 123 GLREA Initial Brief, p. 1.

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testified that the market growth for customer-owned solar PV is increasing and is

expected to continue to grow during the plan year period.124 Despite that, Mr. Crandall

argues that the Company does not appear to include the impact of customer-owned

generation for commercial and industrial customers in its five-year plan forecast.125

GLREA notes that the Company’s assertion, that the impact of growing solar

energy resources on the Company’s plan is de minimus, is inconsistent with the

Company’s IRP case which “proposes recognition of substantial expansion of solar

energy resources”.126 GLREA also asserts that the Staff’s argument that the scope of the

Commission’s review of the PSCR plan under Act 304 is limited to existing resources is

contrary to the purposes and provisions of Act 304.127

The Company counters that its Plan and five-year forecast account for “the

appropriate amount of solar energy resources”.128 The Company argues that its Plan and

five-year forecast include the renewable resources “planned and in existence consistent

with the Company’s pending RE Plan in Case No. U-18231”, includes the impact of

customer-owned generation in the five-year forecast, and includes Experimental

Advanced Renewable Program-Solar facilities based on the contracts the Company has

entered in connection with those facilities.129 Ms. Hatcher adds that the generation

produced by customer-owned Net Metering and self-generation facilities that were in

operation prior to the development of the load forecast in this proceeding has reduced the

124 2 Tr 243-245. 125 2 Tr 246. 126 GLREA Reply Brief, p. 5. 127 GLREA Initial Brief, p. 2. 128 Company Reply Brief, p. 17. 129 Company Reply Brief, p. 17; 2 Tr 89, 90.

U-18402 Page 31

Company’s actual load, which resulted in a reduced PSCR Plan load forecast.130

Moreover, when examining historical participation rates in Net Metering, Net Metering

program limits, and the current interest in distributed generation, the Company “expects

the impact of future customer-owned resources on the Company’s load forecast to be de

minimis.”131 Thus, attempting to incorporate projections of additional customer-owned

solar in the Company’s load forecast is not necessary and would not be meaningful.”132

Staff offers that recommendations that would effect changes to Consumers’

existing resources, such as GLREA’s here, are “outside the scope of what the

Commission can determine in a PSCR case.”133 Staff argues that PSCR cases review

costs resulting from existing resources that have been established in or through other

Commission proceedings, and that “[a]dding to or subtracting from existing resources will

have rate impacts beyond the PSCR factor that cannot be addressed in an Act 304

proceeding.”134

The GLREA does not identify a specific expense in the Plan that should be

disallowed, or an expense in the Forecast that is unlikely to be approved in the future. In

fact, Mr. Crandall’s testimony does not set forth any detailed analysis data underlying the

Plan and Forecast, but rather consists of generalities on what he contends is the

underutilization of solar energy. In addition, the GLREA does not provide any authority

which requires the Company to consider the impact of customer-owned solar PV

generation in the Plan and Forecast that would result in the adoption of Mr. Crandall’s

130 2 Tr 90. 131 2 Tr 90-91. 132 Company Reply Brief, p. 17. 133 Staff Initial Brief, p. 4. 134 Id.

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proposals. To the contrary, the Commission has held previously that MCL 460.6j(4) “only

requires the company to provide a five-year forecast ‘in light of its existing sources of

electrical generation”.135 Thus an Act 304 case is “an inappropriate vehicle for holistic

long-term resource planning.”136 Rather, the PSCR plan proceeding “is a narrow

proceeding, limited to the issues prescribed in MCL 460.6j.”137 Under this authority, the

recommendations of the GLREA and the RCG should be rejected.

D. Coordination with Other Acts

GLREA argues that the Commission should coordinate resource planning under

Acts 304, 295, and 342, “on a complementary basis.”138 Noting that because the IRP,

PSCR plan, and Renewable Energy plan processes utilize different planning time frames,

the Company and other utilities “have to formulate three or four (if rate cases are included)

different resource portfolios”, which “is likely to be confusing and inefficient and

inaccurate”.139 Thus,

[i]f the Commission and utilities are not vigilant and steps are not taken to coordinate and harmonize multiple planning processes the ratepayers will not be well served. . . . There is a good likelihood that conflicts and omissions will occur in the planning processes if they are not carefully coordinated. The Commission should direct the utilities to use the parameters and assumptions they identify and impose on the utilities in conjunction with the IRP process and carry that information and analysis

135 MPSC Case No. U-16892, June 28, 2013 Order, pg. 30. 136 MPSC Case No. U-17319, March 6, 2014 Order, pg. 12. 137 MPSC Case No. U-17319, March 6, 2014 Order, pg. 11-12. Moreover, the Commission has indicated that other proceedings are more appropriate within which to assess issues of the solar energy. See, MPSC Case No. U-17920, January 12, 2017 Order, p. 12 (“The Commission agrees . . . that the statutory purpose and language of Act 295 make renewable energy plan contested proceedings the appropriate venue to raise issues of the increasing effect and use of solar energy.”); MPSC Case No. U-18143, December 20, 2017 Order, p. 12 (“Act 341 now provides a different avenue for consideration of renewable energy resources, i.e., the integrated resource plan (IRP) under Section 6t of Act 341, MCL 460.6t.”). 138 GLREA Initial Brief, p. 5. 139 2 Tr 250.

U-18402 Page 33

into the PSCR and REP planning as well as general rate case proceedings.140

GLREA thus recommends that the Company “should be instructed to fully integrate

and coordinate the, Renewable Energy Plan (biennial), Integrated Resource Plan and Act

304 PSCR planning practices and procedures.141

The Company counters that it will participate in the proceedings under Act 304,

Act 295, Act 341, and Act 342 pursuant to the statutory and Commission requirements

that apply to the individual cases.142 The Company asserts that while “these proceedings

are to some extent compatible”, each proceeding is “separate and distinct, with its own

purpose, set of requirements, and calendar.“143 The Company argues that “while it is

unclear what GLREA envisions in its request for the Commission to require Consumers

Energy to “fully integrate and coordinate” the REP, IRP, and PSCR “planning practices

and procedures”, the Company “does not agree that the particular requirements for the

individual proceedings should necessarily apply in all of the proceedings.”144

Like with the prior issue, the GLREA does not identify a specific expense in the

Plan that should be disallowed, or an expense in the Forecast that is unlikely to be

approved in the future. Rather, Mr. Crandall’s testimony on this issue again consists of

general contentions regarding the underutilization of solar energy. In addition, the GLREA

does not provide any authority which requires the Company to include projections and

assessments that are part of REP and IRP processes into this PSCR plan process. Again,

140 GLREA Reply Brief, p. 6-7. 141 2 Tr 255. 142 Company Reply Brief, p. 18. 143 Id., p. 19 144 Id.

U-18402 Page 34

the Commission has held that the PSCR plan proceeding “is a narrow proceeding, limited

to the issues prescribed in MCL 460.6j”,145 and that an Act 304 case is “an inappropriate

vehicle for holistic long-term resource planning.”146 Based on this authority, the

recommendations of the GLREA should be rejected.

E. Zeeland Pipeline

RCG reiterates it previously made argument that it would be “cost effective for

Consumer's to exercise it's [sic] options to purchase the Zeeland Pipeline rather than

lease it.”147 Mr. Peloquin argues that the Company “could save $3 million (present valued)

by paying the $1 million purchase option.”148 Mr. Peloquin argues that since the Company

did not exercise its purchase option for the Zeeland Pipeline, the Commission should “cap

the dollar amount of Zeeland’s remaining five year contract re-extension lease payments

at $1 million plus a small O&M allowance.”149 Mr. Peloquin adds that “[t]he first year's

contract re-extension lease payment would be less than $1 million, so no disallowance

would be required for this PSCR case.”150 Mr. Peloquin concludes that recovery of the

lease payments is the “high cost scenario”, and that the Commission needs to “disallow

high costs caused by poor contract management” in order to protect the ratepayers.151

Mr. Nadeau counters that, rather than exercise its option to purchase the SEMCO-

owned lateral pipeline at the end of 2017, the Company amended its existing contract

with SEMCO to extend its terms and reduce its required payments.

145 MPSC Case No. U-17319, March 6, 2014 Order, pg. 11-12. 146 MPSC Case No. U-17319, March 6, 2014 Order, pg. 12. 147 2 Tr 235. 148 Id. 149 2 Tr 237. 150 Id. 151 2 Tr 238.

U-18402 Page 35

During the Company’s evaluation of the purchase or lease extension options, SEMCO provided the Company with a proposal to amend the existing contract with more favorable lease extension terms than those in the existing agreement. These new terms included a reduced annual demand charge. Upon evaluating those new amended terms against the cost of ownership, the Company chose to extend the lease for five years.152

Mr. Nadeau adds that the Company evaluated the newly proposed amendment and

reduced annual demand charge against the levelized annual cost to own and operate the

pipeline, and determined “that it would cost the electric ratepayers less for SEMCO to

continue to own and operate the pipeline under their newly proposed amendment than it

would be for the Company to own and operate it.”153

Mr. Nadeau argues that, in evaluating the Company’s options regarding the

SEMCO lateral, Mr. Peloquin correctly noted the $1 million purchase option but did not

correctly analyze the cost to maintain the pipeline as a Company owned asset and he did

not use the correct – lower -- annual demand charge in his analysis.154

The Company adds that the recovery of the demand charges paid pursuant to the

Company’s Amended Transportation Services Agreement with SEMCO are consistent

with the demand charges paid by the Company to SEMCO for natural gas transportation

service to the Zeeland Plant and have been specifically addressed and approved in Case

Nos. U 16045-R (2010 PSCR Reconciliation), U-16432 (2011 PSCR Plan), U-16432-R

(2011 PSCR Reconciliation), and U-16890 (2012 PSCR Plan).155 The Company notes

that the Commission in its July 24, 2018 order Granting Rehearing and Clarification in

152 2 Tr 263. 153 Id. The specific (and confidential) levelized annual costs to extend the SEMCO contract and to purchase the SEMCO lateral and maintain it going forward are shown in Confidential Exhibit A-26, lines 50 and 62. 154 2 Tr 264. 155 Id.

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Case No. U-18142 found that the demand charges were appropriate for inclusion in the

Company’s 2017 PSCR Plan.156

This PFD finds that the bases for the Company’s opposition to RCG’s

recommendation are reasonable. Mr. Nadeau’s testimony - that extending the

transportation services agreement will benefit the Company’s customers – is persuasive.

Conversely, the record does not include any evidence that would require any expenses

related to the extension of the pipeline contract to be excluded from the 2018 PSCR Plan.

Indeed, the RCG’s position appears to be that because the RCG believes that the

Company should have exercised its option to purchase the pipeline, the Commission

should assess the costs attributable to the pipeline as though it had purchased the

pipeline. This argument is illogical. Thus, the RCG’s recommendation - that the

Commission should cap the dollar amount of Zeeland's remaining five year contract re-

extension lease payments at $1 million plus a small O&M allowance – is unsupported by

the record.

VI.

CONCLUSION

None of the adjustments and recommendations to the Company’s Plan raised by

the parties in this matter can be sustained on this record. Therefore, based on the

foregoing, it is recommended the Commission enter a Final Order that approves the

Company’s 2017 PSCR Plan and set a PSCR Factor as requested by the Company. It is

156 Company Reply Brief, p. 23, citing Case No. U-18142 Order, July 24, 2018, p. 3-5.

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also recommended the Final Order not issue a Section 7 warning concerning any

projected expenses in the Company’s 5-year Forecast.

MICHIGAN OFFICE OF ADMINISTRATIVE HEARINGS AND RULES For the Michigan Public Service Commission

_____________________________________ Jonathan F. Thoits Administrative Law Judge

Issued and Served: August 13, 2019 Lansing, Michigan

STATE OF MICHIGAN

MICHIGAN OFFICE OF ADMINISTRATIVE HEARINGS AND RULES

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

* * * * *

STATE OF MICHIGAN ) )

County of Ingham ) Case No. U-18402 )

PROOF OF SERVICE

Meaghan Dobie being duly sworn, deposes and says that on August 13, 2019, she served

a copy of the attached Notice of Proposal for Decision and Proposal for Decision via email

and/or first-class mail, to the persons as shown on the attached service list.

________________________________ Meaghan Dobie

Subscribed and sworn to before me this 13th day of August 2019.

_________________________________ Brianna L. Brown Notary Public, Clinton County My Commission Expires July 4, 2021

SERVICE LIST CASE NO. U-18402

ASSOCIATION OF BUSINESSES ADVOCATING TARIFF EQUITY (ABATE) Bryan A. Brandenburg Michael J. Pattwell Stephen A. Campbell bbrandenburg@clarkhill.commpattwell@clarkhill.comscampbell@clarkhill.com

CONSUMERS ENERGY COMPANY Robert W. Beach Gary A. Gensch Jr. Theresa A.G. Staley Michael C. Rampe Bret A. Totoraitis Ian F. Burgess robert.beach@cmsenergy.comgary.genschjr@cmsenergy.comtheresa.staley@cmsenergy.commichael.rampe@cmsenergy.combret.totoraitis@cmsenergy.comian.burgess@cmsenergy.commpsc.filings@cmsenergy.com

DEPARTMENT OF ATTORNEY GENERAL Celeste R. Gill gillc1@michigan.gov

GREAT LAKES RENEWABLE ENERGY ASSOCIATION INC. RESIDENTIAL CUSTOMER GROUP Don L. Keskey Brian W. Coyer donkeskey@publiclawresourcecenter.combwcoyer@publiclawresourcecenter.com

MICHIGAN ENVIRONMENTAL COUNCIL SIERRA CLUB Christopher M. Bzdok Lydia Barbash-Riley Karla Gerds Kimberly Flynn Marcia Randazzo chris@envlaw.comlydia@envlaw.com

karla@envlaw.com kimberly@envlaw.com marcia@envlaw.com

MICHIGAN POWER LIMITED PARTNERSHIP ADA COGENERATION LIMITED PARTNERSHIP Aaron L. Davis Jennifer U. Heston adavis@fraserlawfirm.comjheston@fraserlawfirm.com

MIDLAND COGENERATION VENTURE LP Richard J. Aaron Jason T. Hanselman Kyle M. Asher raaron@dykema.comjhanselman@dykema.comkasher@dykema.com

MICHIGAN PUBLIC SERVICE COMMISSION STAFF Amit T. Singh singha9@michigan.gov