S T A T E OF M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * *

Transcription

1 S T A T E OF M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * In the Matter of the application of ) CONSUMERS ENERGY COMPANY ) for authority to increase its rates for ) the generation and distribution of ) Case No. U-4 electricity and for other relief. ) ) QUALIFICATIONS AND DIRECT TESTIMONY OF SUSAN E. GOEPP MICHIGAN PUBLIC SERVICE COMMISSION September, 8

2 QUALIFICATIONS OF SUSAN E GOEPP CASE NUMBER U-4 PART I Q. Please state your name and business address. A. My name is Susan E. Goepp. My business address is 79 West Saginaw Highway, Lansing, Michigan Q. By whom are you employed and in what capacity? A. I am employed by the Michigan Public Service Commission (MPSC or Commission) as a Departmental Specialist in the Rates and Tariff Section of the Regulated Energy Division. Q. Please briefly describe your educational background. A. I graduated from Spring Arbor University with a Bachelor of Arts degree in Secondary Education with a Mathematics major. I also hold a Master of Business Administration degree from LeMoyne University in Syracuse, New York. Q. Please briefly describe your utility work experience. A. My + year history in utility work experience has included working in Rates and Pricing for Consumers Energy, Florida Power and Light, Niagara Mohawk, and Tennessee Valley Authority. Q. Have you completed any other utility ratemaking-related courses? A. Yes, I have also completed regulatory fundamentals, pricing analytics and modeling courses over the years within the utility industry, including: National Economic Research Associates (NERA) Marginal Costing for Electric Utilities in Los Angeles, California; New York Independent System Operator (NYISO) Corporate Modeler Improving Business Process Foundations class in Albany, New York; Association of Edison Illuminating Companies (AEIC) Fundamentals of Customer Load Data Analysis; ABB Energy Interactive s Energy Profiler

3 QUALIFICATIONS OF SUSAN E GOEPP CASE NUMBER U-4 PART I Intermediate training; Edison Electric Institute (EEI) Electric Rate Fundamentals Course in Indiana; Energy Management Associates (EMA) PROSCREEN II training; SAS Enterprise s Statistical Analysis Software training; Synergic Resources Corporation s Load Shape Analysis in Philadelphia, Pennsylvania; National Association of Regulatory Utility Commissioners (NARUC) Annual Regulatory Studies Program. Other credentials have included Public School certifications in both Michigan and New York; Vital Smarts Certified Leadership Trainer credentials; and an Affiliate Realtor license with the Tennessee Board of Realtors. Q. What are your current responsibilities at the MPSC? A. In my current position at the MPSC, I prepare jurisdictional and class Cost-of- Service Studies (COSS) for rate cases, allocation methodology analyses in support of COSSs, customer cost calculations in support of customer charge rate design, and special gas and electric issues. Q. During your employment with the MPSC, have you presented testimony or participated in utility cases before the MPSC? A. Yes. In 8 I provided calculations in the Credits A and B tax credits issue for Upper Michigan Energy Resources Corporation (UMERC). Case No. Utility Description U- Upper Michigan Energy Resources Corporation Tax Credits A and B

4 DIRECT TESTIMONY OF SUSAN E GOEPP CASE NUMBER U-4 PART II Q. Have you had any prior participation in presenting testimony or participated in utility cases before the MPSC? A. Yes. As a former Electric and Gas Cost-of-Service Supervisor for Consumers Energy, I have provided testimony in the following case: Case No. Utility Description U-97 Consumers Energy Cost-of-Service Unbundling Affidavit Q. What is the purpose of your testimony? A. I sponsor MPSC Staff s (Staff) recommendation regarding the Cost of Service Study (COSS) and allocation issues for Consumers Energy (the Company). Q. Are you sponsoring any exhibits? A. Yes, I am sponsoring the following exhibits: Staff s Cost-of-Service Exhibit : Exhibit S-6 (SEG-) Schedule F-., pages -4; Exhibit S-6 (SEG-) Schedule F-., pages -5; Staff s Generating Plant Statistics : Exhibit S-7., Staff s Analysis of Load Data : Exhibit S-7.. Q. Please describe Exhibit S-6 Schedule F-. (SEG-). A. Exhibit S-6 Schedule F-. shows Staff s proposed COSS calculation for the Company. Q. Does Staff agree with the Company s proposed COSS? A. Not entirely. There are three Cost of Service-related issues proposed in witness Josnelly C. Aponte s testimony that will be addressed in my testimony: ) Production allocation (4 CP 75//5 verses Average and Excess allocation); ) Number of years for load profiles; ) Distribution allocation for AMI metering. 4

5 DIRECT TESTIMONY OF SUSAN E GOEPP CASE NUMBER U-4 PART II PART I: PRODUCTION ALLOCATION Q. What production allocator does the Company propose? A. The Company proposed a 4 coincident peak average and excess (4CP A&E) production allocator. The Company claims that this method better incorporates load factor and results in a better match to cost causation. Q. Does Staff agree with the Company s proposed allocator for production? A. No. Their method did not use the recommended non-coincident peak (NCP) by NARUC (p.5), and therefore the Company does not properly account for excess demand. Since they are not using the NARUC Manual A&E method, they effectively use a % demand method, which the Commission has repeatedly rejected. NARUC (p.5) says, If your objective is as it should be using this method to reflect the impact of average demand on production plant costs, then it is a mistake to allocate the excess demand with a coincident peak allocation factor because it produces allocation factors that are identical to those derived using a CP method. Rather, use the NCP to allocate the excess demands. For example, if class load for lighting was 5 MW, making no contribution to coincident peak (CP), its excess demand would be -5 MW, summing to zero when calculating the A&E allocator. In order not to allow A&E to be negative, NARUC determines NCP to be a more appropriate allocation. The Company did not use the recommended NARUC method. Q. Would you agree with this production allocator if it would have been used according to NARUC? A. If the Commission decided that average and excess was the appropriate method, it should be calculated correctly using NCP. 4

6 DIRECT TESTIMONY OF SUSAN E GOEPP CASE NUMBER U-4 PART II Q. What does Staff propose? A. Staff proposes to continue the existing 75//5 methodology approved in prior rate cases. Specifically, the Commission has approved a 4CP 75//5 allocation, where 75% of the allocation is based on 4 summer peak demands, nothing for onpeak hours of energy, and 5% based on all-hours energy kwh usage. There are several reasons supporting Staff s proposal. First, the historically accepted method of using 5% of the production allocation for total energy allows a majority of the customer s production costs to be represented by their coincidence with summer peak system demands, while still including a portion for the system energy requirements. Second, it reflects the combination of both demand and energy. This is important because with this method even though a customer class may not peak with the system, the system still needs to be able to provide energy to them during the 876 hours of usage. Generation dispatch costs and other production costs need to be broader than just relating to peak demand. Using only demand contradicts how costs are incurred. That is, reliability needs must be met not just throughout the day, but throughout the year. Do customers benefit from energy just during peak months or do they need energy reliability for all 876 hours of the year? While one truly should account for times of increased demand on the system, one must also account for base load energy requirements for all hours of the year, no matter the time of day or season. Nor does Staff disagree that load factor fully reflects system efficiency. Increasing system load factor means that total system costs are spread across larger number of sales units, and this reduces the cost burden for individual customers. In general system 5

7 DIRECT TESTIMONY OF SUSAN E GOEPP CASE NUMBER U-4 PART II efficiency refers to utilizing system assets to generate the largest possible value for customers, says The Brattle Group, Assessment of Load Factor as a System Efficient Learning Adjustment Mechanism, 7. When using coincident peak with an A&E allocator, this tends to provide results reflective of single CP. Citing a specific example in an illustration within the Arizona Public Service Company rate case Docket 5-5-U-Doc., p., witness Michael J. McGarry, Sr. reports that the complicated A&E formula doesn t do any more to reflect energy in the cost allocation than if a single CP demand allocator was utilized. In fact, the report states that, In other words, the A&E 4CP allocators are simply each class s percentage share of the four coincident peaks (June through September). The 4CP A&E method allows weather sensitive residential loads to assume more production costs than primary, yet they do not necessarily reflect total system cost. This method attempts to allow the class average demand portion to reflect customer class energy. The result is that it simply weights the average demand and does not reflect energy requirements. Staff maintains that using the 4CP 75//5 allocation in this case is more reflective of overall production cost causation. Third, another consideration should be added in terms of including energy in the allocation for production costs. That is that different rate classes have different contributions to line losses. That should also be included in the production cost causation, and if one improperly allocates energy, it distorts the impact of losses as well. For example, residential and small commercial customers have significantly more losses than high voltage 6

8 DIRECT TESTIMONY OF SUSAN E GOEPP CASE NUMBER U-4 PART II customers, so when 5% energy in kwh is factored into the allocator, the cost causation is appropriate without the more complicated load factor analysis. Q. What are the reasons that this method has been approved in prior rate cases? A. The Commission has supported Staff s proposal on merits, as noted in prior cases; The Commission therefore finds that the Staff s proposal to modify the production cost allocation method from to is well supported, better ensures rates are equal to cost of service, and should therefore be approved. 6//5 Order, MPSC Case No. U-7688, p.7. On June, 5, pursuant to 4 PA 69, the Commission issued an order (June order) in Case No. U-7688, in which, inter alia, it approved a proposal to modify the then-existing four coincident peak (4CP) method of production cost allocation to 4CP , finding that this method better assures that rates are equal to cost of service. /9/5 Order, MPSC Case No. U- 775 p.96. The Commission further observes that although Hemlock, in part, contends that there was new evidence introduced in this proceeding that better supports a 4CP production cost allocator, a review of Hemlock s presentation in this case differs little, if at all, from the evidence and arguments that it presented in Case No. U In addition, as the ALJ observed, Hemlock points to no change with respect to electric generation or production costs in the few months since the June order was issued that would support a change in the cost allocation method approved in that proceeding. Hemlock s exception is therefore rejected, and the Commission again approves the use of 4CP for the production cost allocator. /9/5 Order, MPSC Case No. U-775 pp Year-round energy use is an appropriate consideration in determining the allocation of production costs. //7 Order, MPSC Case No. U-799, p.9. The commission shall ensure that the cost of providing service to each customer class is based on the allocation of production-related costs based on using the method of cost allocation and transmission costs based on using the % demand method of cost allocation. The commission may modify this method if it determines that this method of cost allocation does not ensure that rates are equal to the cost of service. //7 Order, MPSC Case No. U-799, p.9. 7

9 DIRECT TESTIMONY OF SUSAN E GOEPP CASE NUMBER U-4 PART II Q. Has Staff conducted any analysis to determine if a 5% energy allocator is still reasonable? A. Yes, Staff analyzed recent data to confirm the 5% energy allocation assumption prudency. Staff combined information from page of Exhibit S-7. with an analysis of the Company s 876 data for 6, summarized on page of Staff Exhibit S-7.. The results of the analysis can be also be found on page of Exhibit S-7.. Q. Can you comment on the results of this analysis? A. Yes. For 6, the minimum energy in an hour was,656,8 kw and the maximum energy was 6,8,44 kw. Because every hour of the year used at least,656,8 kw, Staff equates this amount with base load energy. Using this definition, base load energy was 68.5% of the total average energy for the year. Base load energy was also 4.% of the maximum capacity needed during the year. Staff then determined which of the Company s production assets were base load in nature, based on the amount of plant hours connected to load stated in the annual report. The cost of base load plants in thousands was $,868,888. This is 7.6% of the total cost of all generating units, $5,4,565 in thousands, itemized from the annual report. Consumers Energy P-5, 6, pp.4, 4-4. The last step Staff took was to combine these percentages. Staff reasons that if 7.6% of generating unit cost is base load assets, and if 4.% of maximum energy is base-load energy, then roughly % (7.6% X 4.%) of the production allocator should be based on total energy. 8

10 DIRECT TESTIMONY OF SUSAN E GOEPP CASE NUMBER U-4 PART II Q. Is this the percentage of production costs that Staff proposes be allocated on energy? A. No. Staff views this as a rough calculation to determine if the historic 5% energy allocator is reasonable. Staff also calculated multi-years -6, using this technique. Consumers Energy P-5, -6, pp.4, 4-4. Averaging these results, 7.% was determined to be energy related. This is shown on Staff Exhibit S-7.. Therefore, using this conservative calculation, it continues to be Staff s position that 5% energy recognition is reasonable. Q. What does Staff propose as the components for the remaining 75% of the production allocator? A. Staff recommends that the remaining 75% be based on demand and proposes a 4CP 75//5 production allocator. It should be mentioned that in case U-787, a 4CP 5/5/5 methodology was used. The Commission approved the current allocator in Case No. U The decision was made to move to the 4CP 75//5 approach after a great deal of discussion. First, on pp.9- we see the ALJ states that, The Staff responds that Consumers and Hemlock are oversimplifying the ALJ s analysis, which did not recommend simply following past precedent. According to the Staff, the ALJ appropriately recognized that for decades, after careful consideration, the Commission has consistently found that generation assets were not built to serve only peak load and therefore, production related costs should not be allocated solely on the basis of peak demand. After evaluating the evidence in this proceeding, the ALJ came to the same conclusion. This is supported on p.4 when comparing the Commission s discussion to the 6//5, Order, MPSC Case No. U-7688, pp

11 DIRECT TESTIMONY OF SUSAN E GOEPP CASE NUMBER U-4 PART II DTE Electric Company order in Case No. U-7689 (June 5 order), where it says, As the Commission discussed in the June 5 order in Case No. U-7689 (June 5 order), the Act 69 proceeding for the DTE Electric Company (DTE Electric), the parties in this case likewise appear to agree that the principles to be adhered to in allocating costs are: () the allocation method should ensure that the assignment of costs matches causation of those costs; and () the price signal sent to customers likewise reflects cost causation. In the June 5 order, the Commission found, as it does here, that the current 4CP cost allocation method should be modified to reflect the value of capacity in Consumers production system. However, the Commission also agrees with the majority of the parties to this proceeding that any cost allocation must, to some degree, reflect both demand and energy. As discussed in more detail below, the Commission adopts the Staff s proposed 4CP method for production cost allocation until such time as the Commission is persuaded that a different method better aligns Consumers rates with cost causation. Since 976 the production allocation has still incorporated some demand and some energy components. In Wisconsin Electric; The Staff also argues in favor of retaining the long-standing allocation method. The Staff points out that the ALJ adopted an allocation method that no party proposed, and that WEPCo serves only 7,46 retail customers in Michigan. The Staff contends that the Commission has traditionally applied the CP 75/5 method to utilities serving fewer than one million customers. See, May, 976 order in Case No. U-477, Attachment A, part, p.. The Staff also points out that the Commission chose to retain this allocation method when the standard filing requirements were revised, and contends that the Mines have not presented any evidence showing that circumstances have changed since that order. 7// Order, MPSC Case No. U-598, p.5. A final point from Case No. U-7688 p.5 reports that the Commission agrees with using both demand and energy in the production allocator, saying that, 4 5 6//5, Order, MPSC Case No. U-7688, pp. 9-5.

12 DIRECT TESTIMONY OF SUSAN E GOEPP CASE NUMBER U-4 PART II It is important to remember that we are not allocating capacity, but the cost of that capacity. This is relevant because costs vary depending on the type of plant selected to provide an increment of capacity in the most cost effective way given information about the number of hours the plant is expected to run (i.e., energy) throughout the year. It is, therefore, inappropriate to ignore the cost differentials between capacity types and allocate base purely on capacity. It is Staff s view that as circumstances have not changed, the Commission s logic is equally applicable now, and the Company s arguments are unpersuasive for the reasons given by Staff above. Q. Is Staff abandoning the concept of on-peak energy as a portion of the production allocator as in the last case U-8? A. No. In Staff s opinion the inclusion of on-peak energy as some portion of the production allocator has merit, but Staff is not proposing to include it in the present case. PART II: NUMBER OF YEARS FOR LOAD PROFILES Q. Does Staff agree with using 5 years of historic profiles as proposed by the Company? A. No. The Company proposes using 5 years as referenced in Josnelly C. Aponte s testimony on page 8 for two main reasons, a) it allows for the removal of outliers in the data, in lieu of weather normalization, and b) it provides less weight to each of the years being averaged. Staff notes that by introducing the hot year of, instead of providing less weight it actually weights the overall average more heavily on hotter weather, introducing more of an actual anomaly than removing the outlier 6. 6//5, Order, MPSC Case No. U-7688, pp. 9-5.

13 DIRECT TESTIMONY OF SUSAN E GOEPP CASE NUMBER U-4 PART II Q. How do the, 4, or 5-year average Cooling Degree Day (CDD65) measures compare to a 5-year average of CDD65? A. Per Table below, Staff compares various groups of years to the 5-year average CDD65, finding a preferred -year average rather than using either the 4 or 5-year averages. In the -year average, both July and August are within a reasonable.5 CDD variance. The -year average is also comparable when considering an overall average of 5.7, which most closely approximates the 5-year average of 5.6. Notice that in the 5-year average July s CDD value of 6.4 is higher than all scenarios. In the 4-year averages September s CDD value of 5. is higher than all scenarios. Staff recommends using the -year for several reasons; a) the system peak is more likely to occur in July than June or September. From - 6, the system had peaked in June only twice, July nine times, August four times, and not at all in September; b) When considering the overall -year average of 5.7, this average most closely approximates the 5-year average of 5.6; and c) Keeping profiles at years keeps more of a consistent approach on a year-toyear basis, especially when considering annual rate case filings Table. CDD65 Consumers Energy's Territory 5 year 4 year 5 year year June July August September Total Q. What are the reasons that this method has been approved in prior rate cases?

14 DIRECT TESTIMONY OF SUSAN E GOEPP CASE NUMBER U-4 PART II A. There are three reasons this method has been approved in prior rate cases, as stated in the testimony of Josnelly C. Aponte in MPSC Case No. U-8. She states, The test year allocation schedules use a three-year average of the historic profiles to develop an average test year profile that is used to develop the test year demand and energy allocation schedules through 7. 7 TR 68. She states, All allocation methodologies used in the Test Year COSS Version are the same as the methodologies used in the 5 Historical Study. 7 TR 68. Finally, in the same case about production cost allocation she says, For the calculation of the allocator, the COSS uses a three-year average based on historic demands prorated by each year s sales. 7 TR 69. The Commission approved this methodology. /9/8 Order, MPSC Case No. U-8, p. 9. PART III: DISTRIBUTION ALLOCATION FOR AMI METERING Q. Does Staff agree with the metering equipment charges used in the Company s distribution allocation for AMI metering? A. Yes, Staff supports the distribution allocation for AMI meters using updated equipment costs from the legacy to smart meters. Audit request 64 provided verification from workpaper WP-JCA- that only % of traditional meters remain in the system for Residential and Secondary Commercial customer classes. Staff has no response to the Company s discussion of Minimum Distribution System (MDS) verses Zero Intercept methods of allocation since no proposal was presented. Q. Does this conclude your testimony? A. Yes, it does.

15 S T A T E O F M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * In the matter of the application of ) CONSUMERS ENERGY COMPANY ) for authority to increase its rates for ) Case No. U-4 the generation and distribution of ) electricity and for other relief. ) ) EXHIBITS OF SUSAN E. GOEPP MICHIGAN PUBLIC SERVICE COMMISSION September, 8

16 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 4 Witness: SEGoepp Date: September 7, 8 Net Plant (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Plant in Service Production 5,784,695 5,7,89,65,5,74,57,97,465 7,867,499 5,84 Transmission 4 Distribution 8,6,6 8,,999 4,59,9,56,645 84,9 8,94 6,99 5,6 5 General/Common/Intangible,5,666,47,444 74,4 4,55 5,65,64 5 5, 6 Plant Purchased/Sold 7 Total Plant in Service 5,4,99 5,8,4 7,598,974 4,76,7,68,46 8,5 8,94 6,658 8 Depreciation Reserve 9 Production,,4,9, 9,78 55,6 75,99 6, ,79 Transmission Distribution,9,,898,67,68,95 96,97 7,8 8,46,679,9 General/Common/Intangible 748, ,67 4,95 89, 9, 6,7 89,89 Total Depreciation Reserve 5,859,9 5,85,69,9,68,675,47,,84,774,54 4, 4 Construction Work In Progress (CWIP) 5 Production 67,9 65,5 9,55 6,658 9, ,99 6 Transmission () () () () () () () () 7 Distribution 8,7 8,676 6,58 6,66 6,65, General/Common/Intangible,46 99,759 5,6 5,87 8,588, Total CWIP 486,75 48,98 6,68 5,56 6,49 5,56 89,8 Future Use Production,74, Distribution 7,55,56,6 849,6 4 9 Common/General PHFFU Depreciation Reserve 7 5 Total Future Use 5,77 5,,75,6, Net Plant 9,876,97 9,85,45 4,94,49,78,8,85,54,84 5,7 4,49

17 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 4 Witness: SEGoepp Date: September 7, 8 PIS Summary (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Production Production Plant in Service 5,784,695 5,7,89,65,5,74,57,97,465 7,867,499 5,84 Generation Step Ups 4 Total Production 5,784,695 5,7,89,65,5,74,57,97,465 7,867,499 5,84 5 Transmission 6 Bulk Power Transm 7 Transm; Subtrans 8 Subtransmission 9 Total Transmission Distribution Stations and Equipment,75,74,7,89,68,4 77,49 45,674 8, 4,49 4,848 Overhead System,46,,46,445,96,777,88,4 4,865 9,494, Underground System 778,79 778,7 46,87 89, 8,9 7, Meters and Svc Drops,7,44,7,5 97,445 56, 8,54 7, St Lgts and OPL 8,66 8, , Total Distribution 8,6,6 8,,999 4,59,9,56,645 84,9 8,94 6,99 5,6 7 General/Common/Intangible 8 Total Gen/Comm/Int Plant,5,666,47,444 74,4 4,55 5,65,64 5 5, 9 Plant Purchased/Sold Total Plant in Service 5,4,99 5,8,4 7,598,974 4,76,7,68,46 8,5 8,94 6,658

18 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 4 Witness: SEGoepp Date: September 7, 8 Plant In Service (production & tran) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Production Plant Fossil 4,5,566 4,,5,78,75,,,45,9,8, 8,65 Nuclear 4 Total Hydro 59,578 54,746,648 8, 84,79, ,8 5 Other Production/Combustion Turbine 994,55 985,644 46,7 6, 9,94,7 58 8, Classics 7 Jackson Gas Plant 6 Distribution GSUs 7 Total Production 5,784,695 5,7,89,65,5,74,57,97,465 7,867,499 5,84 8 Transmission Plant 9 Transmission Direct 8 Subtransmission 8 Transmission 7 Total

19 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 4 of 4 Witness: SEGoepp Date: September 7, 8 Plant In Service (distribution) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Distribution Plant 45/8kV Substations/Overheads (METC) Land & ROW 7 89, 88,467 4,8,4, /8kV Substations/Overheads Land & ROW 7 6,8 6,6,4 6,444 9, /kV Substations/Overheads Land & ROW 4 48,795 48,764,97,65 4, Distribution Substation Land & ROW 7,8 7,8,67,89, kV Substations/Overheads (Assignable) Land & ROW DIR kV Substations/Overheads (Assignable) Land & ROW DIR Overhead Lines Land & ROW 7 5,49 5,45 4,57 8,68, Total 98,57 97,7 8,95 5,9 59,4, Distribution Substations & Equipment - - 8kV Customer Substations (Assignable) DIR kV Customer Substations (Assignable) DIR kV HV Subtran/Dist Substations 7 4,68 49,64 66,754,897 54,68,579,665, kV HV Subtran/Dist Substations kV Subtran/Dist Substations 4 49,746 49,44,,67 4,6,69, 6 6 Distribution Substations 98,8 98,8 4,5 87,75 68,47,69-7 Total,,59,8,7 58,9,94 65,646 8,7,87,86 8 Distribution Overhead System 9 8kV HV Subtran/Dist Overhead Lines 7 44,4 44,7 7,5,66 5, kV HV Subtran/Dist Overhead Lines 46kV Subtran Overheads & Transformer Platforms 47, 469,97,75 5,94 6,795,6,8 9 Transformer Platforms,9,9,8, Three Phase Primary 794,4 794,4 7,555,746 8,47 5, Single Phase Primary 5 649, ,974 96,68 47,56-6, Single Phase Secondary,499,,499, 94,97 57,8-4, Total,46,,46,445,96,777,88,4 4,865 9,494, Distribution Underground System - 8 Three Phase Primary 6,6 6,6 8,976 8,54 4, Single Phase Primary 5 566,54 566,54 45,588 5, - 5, Single Phase Secondary 6,889 6,889 8,544 5,5 -, kV Subtran/Distribution Underground Lines,46,47 5,765,59, Total 778,79 778,7 46,87 89, 8,9 7, Distribution Line Equipment - 4 Primary,68,68 56,747 5,57 7, Secondary 84,49 84,49 59,44 7,89-7, Total 955,9 955,9 565,99 5,646 7,685 8,755-7 Distribution Services 8 Residential Overhead & Burial Services 6 5,55 5,55 5, C&I Overhead & Burial Services 6 6,48 6,48-6, Total 78,67 78,67 5,55 6,

20 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 5 of 4 Witness: SEGoepp Date: September 7, 8 Plant In Service (distribution & general) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Distribution Metering Equipment Metering Equipment (Mass) 7 58,46 58,454 45,9 94,68 8, Total 58,46 58,454 45,9 94,68 8, Distribution Installations on Customer Premises 5 Installations on Premises L4 (Assignable) DIR 7,44 7, , Total 7,44 7, , Distribution Streetlighting Equipment 8 Luminaires/Suspensions/Poles/Transformers DIR,4, , Underground Cable & Conduits 9,4 9, ,79-6 Photoelectric Switches 7, 6, , Total 8,66 8, ,57-9 Total Distribution Plant in Service 8,6,6 8,,999 4,59,9,56,645 84,9 8,94 6,99 5,6 Test Year Distribution PIS 9 8,6,6 8,,999 4,59,9,56,645 84,9 8,94 6,99 5,6 4 Electric Plant Purchased & Sold 5 General, Common & Intangible 6 General: Production Related 7 General: Merchant Control 6-8 General: Power Control Center 8kV 9 General: Power Control Center 46kV General: Functionalized 5 7,455 7,47 45, 68,54 5,84 6,5 5,48 General: Reallocated from/(to) Gas DIR Common: Functionalized 5 66,74 65,98 96,8 9,596 68,65 8,78 4,46 Franchises & Consents - Generation 4 Intangible PIS 5 74,497 7,79 8,5 8,4,66 5,9 76,758 5 Total General, Common & Intangible,5,666,47,444 74,4 4,55 5,65,64 5 5,

21 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 6 of 4 Witness: SEGoepp Date: September 7, 8 Depreciation Reserve Summary (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Production Production Depreciation Reserve,,4,9, 9,78 55,6 75,99 6, ,79 Generation Step Ups 4 Total Production,,4,9, 9,78 55,6 75,99 6, ,79 5 Transmission 6 Bulk Power Transm Transm; Subtrans 8 Subtransmission 9 Total Transmission Distribution Stations and Equipment 69,6 69,5 59,649,9,4 5,54, 958 Overhead System,55,6,55,7 8,4 54,68 7,4, Underground System,57,,4 8, 87,4,, Meters and Svc Drops 467, ,674 9,94 5,8,9 5,8 5 St Lgts and OPL 8,44 8, , Total Distribution,9,,898,67,68,95 96,97 7,8 8,46,679,9 7 General/Common/Intangible 8 Total Gen/Comm/Int 748, ,67 4,95 89, 9, 6,7 89,89 9 Total Depreciation Reserve 5,859,9 5,85,69,9,68,675,47,,84,774,54 4,

22 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 7 of 4 Witness: SEGoepp Date: September 7, 8 Depreciation Reserve (prod & tran) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Production Fossil,457,754,444, ,6 46,86 497,7 4,5 78,55 Nuclear 4 Hydro 5,798,59 5,49 7,66 4, ,79 5 Other Production/Combustion Turbine 446,57 44,57 8,66 6, 5,49,79 6,999 6 Jackson Gas Plant 7 7 Classics 6 Distribution GSUs 7 Total Production,,4,9, 9,78 55,6 75,99 6, ,79 8 Transmission 9 Transmission Direct DIR Total Subtransmission 8 Total Transmission Total

23 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 8 of 4 Witness: SEGoepp Date: September 7, 8 Depreciation Reserve (distribution) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Distribution Depreciation Reserve Distribution Land & Right of Way /8kV Substations/Overheads (METC) 7 8,749 8,677,7,, /8kV Substations/Overheads 7,95, /kV Substations/Overheads 4 9,9 9,,95,49, Substations/Overheads (Assignable) DIR Overhead Lines Land & ROW 7,7,698 6,69, Total,85,754 4,86 9,88 7, Distribution Substations & Equipment Customer Substations (Assignable) DIR kV HV Subtran/Dist Substations 7 95,96 94,44 6,694,86, kV Subtran /Dist Substations 4,78 4,64 5,598,95 6, Distribution Substations 58, 58, 7,45 7,87, Total 78,7 77,77 7,77 7,44 8,588, Distribution Overhead System kV HV Subtran/Dist Overhead Lines 7 8, 8,4,,945, kV Subtran Overheads & Transformer Platforms 84,6 84, 6,,56 4, Single Phase Primary & Secondary 5,6,76,6,76 77,669 48,7 -, Total,55,6,55,7 8,4 54,68 7,4, Distribution Underground System Distribution UG System 8,59,59, kV Subtran/Distribution UG Lines 98,968 98,78 8,48 8,5 86,977,987,8 86 Total,57,,4 8, 87,4,, Distribution Line Equipment 5 Capacitors/Regulators/Transformers 8,7 8,7 7,7 4,478,7,5 5-6 Total 8,7 8,7 7,7 4,478,7,5 5-7 Distribution Services 8 C&I and Residential Services 44,74 44,74 95,84 48, Total 44,74 44,74 95,84 48,

24 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 9 of 4 Witness: SEGoepp Date: September 7, 8 Depreciation Reserve (dist & general) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Distribution Metering Equipment Metering Equipment (Mass) 7 8,5 8,5 4,9,944,9 Total 8,5 8,5 4,9,944,9 4 Distribution Installations on Customer Premises 5 Installations on Premises L4 (Assignable) DIR 5,798 5, , Total 5,798 5, , Distribution Streetlighting Equipment 8 Streetlighting Equipment Depreciation Reserve 8,44 8, , Total 8,44 8, ,64-76 Distribution Depreciation Reserve,9,,898,67,68,95 96,97 7,8 8,46,679,9 Test Year Distribution Reserve 7,9,,898,67,68,95 96,97 7,8 8,46,679,9 General, Common & Intangible General: Power Control Center 4 4 General: Functionalized 5 9,5 9,79 58,6 7,649,4, General: Reallocated to Gas DIR Common: Functionalized 5 87, 86,8,5 47,5 4,74 4, Intangible Amortization Reserve 5 45,46 45,679 4,4 4,8 8,974,89 75,747 8 Total General, Common & Intangible 748, ,67 4,95 89, 9, 6,7 89,89

25 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 4 Witness: SEGoepp Date: September 7, 8 CWIP (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Production CWIP Production 67,9 65,5 9,55 6,658 9, ,99 Production: Gas Plant Production: 7 Classics 4 Total Production 67,9 65,5 9,55 6,658 9, ,99 5 Transmission CWIP 6 Transmission 8 () () () () () () () () 7 Subtransmission 8 Total Transmission () () () () () () () () 9 Distribution CWIP HV Distribution 4,546 4,5 7,855,4, Distribution 6 77,57 77,55 45,66 5,49,979,9 Other Total Distribution 8,7 8,676 6,58 6,66 6,65, General/Common/Intangible CWIP 5 General 5 6,48 6,46 8,8 4,6, Intangible 5 7,8 7,654,6 9,545 7, Common 5 45,866 45,689 4,554,58 8,5, Plant Held for Future Use 5 9 Other 5 Total Gen/Comm/Int,46 99,759 5,6 5,87 8,588, 9 87

26 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 4 Witness: SEGoepp Date: September 7, 8 Working Capital (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Current+Accrued Assets Cash & Cash Equivalents 6 58,44 58, 9,46 6,5, Accts Receivable 4 98,7 96,454 7,9 75,4 8,667,88 9,75 4 Material and Supplies 6 88,5 87,785 4,886 4,74 7,8, Fuel Stock 67,8 67,67 5,6 5,7 6, Real & Personal Property Taxes 6 79,8 79,85 89,58 5,96 6,78, Other Cur Assets 5 45,5 4,67 84,696 87,4 64,6 7,694, 8 Deferred Debits 5 854,469 85,7 457,45 5,755 58,596 9,55,99 9 Total Current Assets,89,87,88,7 967,7 484,798 95,44 5,6 87 8,47 Current+Accrued Liab Accounts Payable 6 94,8 9,6 96,55,64 79,865 5,877,66 Customer Deposits 4 7,74 7,7 7,955 4,59 4, Dividends Declared 6,56,474,6 5,76 4, Accrued Interest 6 44,46 44,78,5,46 8, Accrued Taxes - Federal 5 7,5 7,5 4,,9, Accrued Taxes - MSBT 6,58,57, Accrued Taxes - R&PP & Other 6 54,89 54,48 77, 4,47,, Other Current Liabilities 5,66,88,849 5,7, Deferred CR 5 45,4 4,788 7,75 7,4 78,96 9,487 64,64 Total Current Liabilities,87,796,8,86 557,954 9,757,648 9, ,49 Total Working Capital 84, 799,95 49,6 9,4 8,786 5, ,6

27 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 4 Witness: SEGoepp Date: September 7, 8 Adjustments to Rate Base (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Additions to Rate Base Sales and Use Tax Adjustment Total Additions 7 Construction Funds Retained from Contractors 8 Customer Advances 9 58,4 58,,97 8,97 6,6, Total Deductions 58,4 58,,97 8,97 6,6, Total Adjustments to Rate Base (58,4) (58,) (,97) (8,97) (6,6) (,95) (5) (4)

28 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 4 Witness: SEGoepp Date: September 7, 8 Revenue (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Rate Revenue Revenue From Electric Sales DIR,8,44,7,9,97,6 64,54 8,44 9,76,948,44 Provision for Rate Refund DIR Unbilled Revenue DIR Non PSCR Rate Revenue,8,44,7,9,97,6 64,54 8,44 9,76,948,44 6 PSCR Base Revenue DIR,8,58,994,97 74,5 44,658 8,697,6 -,6 7 Unbilled PSCR Base Revenue DIR GSG Market Price Revenue DIR,48, ,48-9 PSCR Rate Revenue,,64,996,45 74,5 44,658 8,697,6,48,6 Total Rate Revenue 4,9,499 4,68,74,9,67,58,8,, 4,65,49 4,755 Revenue Credits Late Payment Charge Revenue DIR,7,7 5,77,9, Renewable Resource Surcharge 5 4 ERIP DIR () () 5 Pole Rental Rev 7,4, 6,56, Other Rents 6,4,4 5,64,, Enhanced Security Surcharge DIR () () 8 Interdepartmental 5 9 Reg Asset d(4) DIR () () PLM Revenues 55 - Purchased Power Administrative Fees Miscellaneous Service & Reconnect Fees 5,49, Other Revenues 5 4,444 4,98,449 9, Securitization Surcharge DIR () () 5 Job Work Revenue 44 4, 4, 8,5 4,7, Non PSCR Revenue Credits 5, 5,69 8, 5,577 7, PSCR Factor Revenue DIR 6,584 6,584 9,78 5,9, Unbilled PSCR Factor Revenue DIR Intersystem Sales 8, 8,9,87 9,6 7,66 5 GSG Market Price Capacity Revenue DIR PSCR Revenue Credits 6,86 6,774 4,868 5,8 8,5 4 Total Revenue Credits 59,8 58,94 7,98 4,75 45,764, Total Revenue 4,5,57 4,7,686,,68,98,897,77,895 44,79,48 4,85

29 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 4 of 4 Witness: SEGoepp Date: September 7, 8 O&M (production) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Fuel and Purchased Power Mid-Peak Summer Fuel for Gen 78,59 77,678 8,495 8,7, On-Peak Winter Fuel for Gen 5 4,558,4 7,949 48,7 79,56,8 9,7 4 Off-Peak Summer Fuel for Gen 4 7,95 7,8 7,97 4,589 7, Off-Peak Winter Fuel for Gen 6 8,9 6,5 5,575 9,477 5,,96 75,496 6 Critical Summer Peak Energy 7 8,5 7,88,67 9,6 4, Total Fuel Expense 5, 54,56 95,987,7 4,4, ,749 8 Mid-Peak Summer Purchased Power 65,69 64,978,86 5, 5, On-Peak Winter Purchased Power 5 7, 69,58 6, 4,754 66, ,855 Off-Peak Summer Purchased Power 4 59,5 58,78,84,4, Off-Peak Winter Purchased Power 6 5,45 4, 44,86 4,657 4,498,68 6,5 Critical Peak Summer Purchased Power 7,998,65,45 8,8, Purchased Power Capacity 7,8 74,445 9,67 68,9 4,495, ,66 4 Total P&I,54,45,4,4 454,6 69,884 4,59 5,78 47,74 5 Total Fuel and P&I,684,76,667,8 65,599 9,67 67,4 8, ,9

30 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 5 of 4 Witness: SEGoepp Date: September 7, 8 O&M (production) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Fossil Plant O&M Total Capacity Related Operations 4,59 4,76 6,577 9,6,8 5 6 Capacity Related Maintenance 4,599 4,558,88,9, Energy Related Operations 7, 6,955,64,58, Energy Related Maintenance 49,8 48,684 8,97,6 8, Capacity Related Fuel Handling 7 Energy Related Fuel Handling,7,98 4,859,97 5, Total Fossil O&M Total 4,456, 44,7 6, 4, ,56 9 Nuclear Plant O&M Total Capacity Related Operations Capacity Related Maintenance Energy Related Maintenance 5 Electric Expenses 4 54 Miscellaneous 5 Total Nuc O&M Total 6 Hydro Plant O&M Total 7 Capacity Related Operations 8,4 8,55,447,, Capacity Related Maintenance Energy Related Operations Energy Related Maintenance 4, 4,57,56 944, Rents Total Hydro O&M Total 4,499 4,59 5,77,79 5, Other Power O&M Total 4 Capacity Related Operations & Maintenance 7,78 7,44 5,449 8,977, Energy Related Operations & Maintenance 6 7 Total Other Power O&M Total 7,78 7,44 5,449 8,977, Other Power Supply Expense 9 Capacity Related Sys Cntl Load Disp 9,874 9,786 4,8,46,69 88 Energy Related Sys Cntl Load Disp Total Other O&M Expense 9,874 9,786 4,8,46,69 88 Disposition of Allowances Total Production O&M Excluding Fuel and P&I 76,68 74,887 69,45 4,5 6, ,7 4 Total Prod O&M Expense,86,5,84,69 7,5 4,6 68,97 9,5 78 8,645

31 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 6 of 4 Witness: SEGoepp Date: September 7, 8 O&M (transmission & adjustments) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Transmission O&M Transmission 49,64 45,4 8,7,556 48,48,6 87 4,9 Miscellaneous 7 4 Other 5 Total Transmission Expense 49,64 45,4 8,7,556 48,48,6 87 4,9 6 O&M Adjustments 7 Tax Benefit of Proforma Interest & Interest Synchronization Adjustment 5 8 Other Advertising Programs - Disallowance 4 9 Income Tax Effect of Interest 9 Charitable, Civic, Dues & Donations 4 Transmission reclass (indirect costs) DIR Streetlighting O&M DIR Customer O&M 4 4 Administrative and General O&M 4 5 Other O&M Inflation 44 6 Other O&M Adjmts 48 7 Total O&M Adjustments

32 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 7 of 4 Witness: SEGoepp Date: September 7, 8 O&M (distribution) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Distribution Operation 58 Supv & Engineering - Distribution 4 4,44 4,99 4,5 6,6,5, Supv & Engineering - 8kV Supv & Engineering - 46kV 44,97, Load Dispatch - Distribution 6 58 Station Expense - Distribution,967, Station Expense - 8kV 8 58 Station Expense - 46kV Overhead Expense - Distribution 7 6,569 6,568,756, Overhead Expense - 8kV Overhead Expense - 46kV Underground Exp 8,87,87,8, St Lt,489, , Metering Expense,69,69, Cust Instl Expense 6,7,7, Miscellaneous 4 4,8 4,8 8,6,657 9, Rents 9,994,99, Total Dist Operation Expense 65,9 65,95 7,79 6,6 4,8 6, Distribution Maintenance 59 Supv & Engineering - Distribution 4 6,685 6,684,8, Supv & Engineering - 8kV Supv & Engineering - 46kV Structures - Distribution Structures - 8kV Structures - 46kV Station Equipment - Distribution 8,75 8,75,98,454, Station Equipment - 8kV,549, Station Equipment - 46kV 4,757, Overhead Lines - Distribution 7 8,95 8,9 46,74 7,68 6, Overhead Lines - 8kV Overhead Lines - 46kV,5, Underground Lines - Distribution 8 4,9 4,9,49, Underground Lines - 8kV Underground Lines - 46kV Line Xfmrs 8,45 8,45 5,7, St Lts & OPL Meters,69,69, Miscellaneous Total Dist Maintenance Expense 7,95 7,95 66,447 8,98,96, 68 4 Total Distribution O&M Expense 8,856 8,8 4,4 55,89 5,896 8,

33 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 8 of 4 Witness: SEGoepp Date: September 7, 8 O&M (customer & A&G) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Customer Accounts Expense 9 Supervision 48 5,47 5,47 4, Meter Reading 6,9,9,74, Rcrds & Collection 6 5,767 5,767 5, Uncollectibles 64 8,86 8,86 5,9, Misc Expenses 48 7 Total Customer Accounts 4,48 4,48 8,7 5, Customer Services 9 97 Supervision Customer Assist 6 5,7 5,65,86,6, Info & Inst 6,447,447,7 7 9 Miscellaneous 6 Total Customer Services 7,688 7,6,6,9, Sales Expense 5 9 Supervision Demo & Selling Advertising Miscellaneous 6 9 Total Sales Expense Administrative & General Production 5 6,66 6, 5,64 4,889, HV Distribution 46,868,858,64,8, Distribution 47 86,596 86,58 49,68 6,8 6,67 4,79 4 Customer 49 9,5 9,9 5,8,47, 5 5 Total Admin & General 7,475 7,87 9,76 44,55,8 4, Total O&M Excluding PSCR Expense 584,4 58,68 8,74 47,6,74,47 7,4 7 Total O & M Expense,78,49,684,85,4,4 69,56 877,8 4,57 987,574

34 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 9 of 4 Witness: SEGoepp Date: September 7, 8 Depreciation Expense Summary (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Production Production Depreciation Expense 9,9 89,98 9,7 69,6 99, ,64 GSU Depreciation Expense 4 Production Test Year Change 5 Total Production 9,9 89,98 9,7 69,6 99, ,64 6 Transmission 7 Bulk Power Transm Transm; Subtrans 9 Subtransmission Total Transmission Distribution Stations and Equipment 58,865 58,76 9,9 8,8, Overhead System 9,56 9,4 64,88 4,55, Underground System 7,88 7,88,7 6, Meters and Svc Drops 55,74 55,7 9,97,6, St Lgts and OPL 4, 4, ,6-4 7 Test Year Distribution Change Total Distribution 45,87 45,7 44,99 78,67 6,4 6, General/Common/Intangible Total Gen/Comm/Int,886,45 6,4 8,54,95, Test Year Gen/Comm/Int Change 445 Total General/Common/Intangible Dep Expense,886,45 6,4 8,54,95, Total Other Amortization Expense 4 Total Depreciation & Amortization Expense 65,64 647,45 4, 76,57 6,97 9,56 5,74 5 Test Year Dep & Amort Exp 44 #REF! #REF! #REF! #REF! #REF! #REF! 5,74

35 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 4 Witness: SEGoepp Date: September 7, 8 Depreciation Expense (prod & tran) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Production Direct Fossil 9,8 7,944 85,8 49,857 7, ,879 4 Nuclear 5 Hydro 4,74 4,76 6,66 9,68, Other Production 4,48 4,978 6,98 9,85 4, Distribution GSUs 8 Jackson Gas Plant 9 7 Classics Total Production Depreciation Expense 9,9 89,98 9,7 69,6 99, ,64 Transmission Direct Transmission 7 4 Subtransmission 5 Total Transmission Depreciation Expense

36 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 4 Witness: SEGoepp Date: September 7, 8 Depreciation Expense (distribution) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Distribution 6A Land & Rights-Direct kV Substations/Overheads (METC) kV Substations/Overheads kV Substations/Overheads Substations/Overheads (Assignable) DIR Overhead Lines Land & ROW Total,46, Distribution Substations & Equipment Customer Substations (Assignable) DIR kV HV Subtran/Dist Substations 7,69,5 4,9,55, Distribution Substations 4 8,996 8,984 8,6 5,86 5, Total 9,65 9,55,57 7,67 9, Overhead System 5 8kV HV Subtran/Dist Overhead Lines 7,77, kV Subtran Overheads & Transformer Platforms,568,56 4,97,98, Overhead System 5 96,5 96,5 58,9 6, Total 9,56 9,4 64,88 4,55, Underground System Underground System 8 7,88 7,88,7 6, Total 7,88 7,88,7 6, Distribution Line Equipment 4 Line Equipment 7,84 7,84 6,48, Total 7,84 7,84 6,48, Distributions Services 7 Overhead & Underground Services 6,954 6,954 7,97 9, Total 6,954 6,954 7,97 9,

37 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 4 Witness: SEGoepp Date: September 7, 8 Depreciation Expense (dist & general) (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Distribution (cont.) Distribution Metering Equipment Metering Equipment 7 8,467 8,467,97 4,66, Total 8,467 8,467,97 4,66, Installations on Customer Premises L4 DIR Street & Highway Lighting Depreciation Expense 4, 4, ,6-4 7 Total Distribution Depreciation Expense 45,87 45,7 44,99 78,67 6,4 6, General/Common/Intangible 9 General 5,885,89 6,6,, Common 5,4,,97 5,54, Intangible Amortization 5 8,589 8,78 4,4,49 4,958,797 Total Gen/Comm/Int Depreciation Expense,886,45 6,4 8,54,95, Other Amortization 4 Amort of 7 Classics Inventory 5 AFUDC in Excess of FERC Rate 6 Securitized Regulatory Assets (MPSC Case U-55) 5 7 ARO Accretion/Transition Expense 8 Total Other Amortization Expense 9 Total Depreciation & Amortization Expense 65,64 647,45 4, 76,57 6,97 9,56 5,74

38 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 4 Witness: SEGoepp Date: September 7, 8 Tax (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional City Income Tax 5,44, Michigan Single Business Tax 6 Michigan Business Tax 49 4,6 4,5,9,64 6, (4) R&PP Taxes - Prod 64,77 64,9 6,487 5,9, R&PP Taxes - High Voltage Dist,48,95 9, 5,7 6, R&PP Taxes - Low Voltage Dist 6 66,576 66,575 9,4,996,4,74 6 R&PP Taxes - General 5,8,68, R&PP Taxes - Common/Intangible 5,46,4 6,67,47, R&PP Taxes - PHFFU R&PP Taxes - CWIP Total R&PP Taxes 68,6 67,68 8,4 47,5 4,67, Payroll Related Taxes 5,59,46,55 5,4, Miscellaneous General Taxes 5 Total Payroll/Miscellaneous Taxes,59,46,55 5,4, MPSC Assessment Fee 5 9,66 9,7,,88 4, Total Other Taxes 4,86 4,9,678 66,5 49,567, Federal Income Tax Provision 49 6,478 6,88 64,8,56 7,569,64 (4) 7 Total Taxes Other Than Income,455 99,69 98,88 54,67 4,479, Total Income Taxes 56,89 57,8 86,69 45,,658, (54) 9 Total Taxes 57,94 56,99 85,7 99,767 67,7 4,

39 MICHIGAN PUBLIC SERVICE COMMISSION STAFF Consumers Energy Company Electric Cost-of-Service Study Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 4 of 4 Witness: SEGoepp Date: September 7, 8 Adjustments to Income Statement (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Adjustments to NOI - Miscellaneous 6 Interest Expense Securitization I 5 - Gain/Losses from Disposition of Utility Plant 6 4 Disallowed Corp Memb 5 5 Advertising 5 6 Interest Synch Adj 9 7 Allowable Charitable 4 8 MERC Consolidation 9 Clean Air Act 6 - AFUDC 8,84 8,78 4,4,79, Income Tax Adjustment 6 - Total Other Adjustments 8,84 8,78 4,4,79,

40 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 5 ORIG VERSION 4CP 75//5 Production and CP Transmission (thousands of dollars) Summary RETURN (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Total Rate Base 9,6,6,697,577,84 5,9,85,9,95,6,64 6,6 5,96 45,5 Total Rate Revenue (,9) 4,9,499 4,68,74,9,67,58,8,, 4,65,49 4,755 Total Revenue Credits 59,8 58,94 7,98 4,75 45,764, Total Revenue 4,5,57 4,7,686,,68,98,897,77,895 44,79,48 4,85 5 Expenses: 6 Fuel and P&I Expense,684,76,667,8 65,599 9,67 67,4 8, ,9 7 Transmission Expense 49,64 45,4 8,7,556 48,48,6 87 4,9 8 Other O & M Expense 584,4 58,68 8,74 47,6,74,47 7,4 9 Depreciation & Amortization Expense 65,64 647,45 4, 76,57 6,97 9,56 5,74 Other Taxes 4,86 4,9,678 66,5 49,567, Federal Income Taxes 6,478 6,88 64,8,56 7,569,64 (4) Total Expenses,5,76,7,689,76,65,5 95,8,8,9 8,44,8 7,5 Net Operating Income 66, 68,4 5,65 8,68 95,965 6,59,654 (,) 4 Other Income Adjustments 8,84 8,78 4,4,79, Adjusted Net Operating Income 5,58 645,44 647,9 55,479 85,46 98,5 6,456,659 (,49) 6 Rate of Return on Rate Base 6.7% 6.% 6.7% 6.8% 4.5% 5.56% 7.95% -4.7% 7 Index of Return (Jurisdictional) Return on Rate 5.8% 66,98 64,95 7,77 68,596,8 6,75 45,64 9 Income Deficiency (Sufficiency) (8,5) (,898) (48,) (6,75),75 94 (,4) 4,79 Revenue Deficiency (Sufficiency) (7,65) (44,5) (64,546) (,4) 44,9 9 (,76) 6,48 Revenue Requirement/Total Cost of Service 4,4,9 4,8,6,98,7,76,467,,85 45,86,74,69 Less: Revenue Credits 59,8 58,94 7,98 4,75 45,764, Proposed Rate Design Revenue 4,55,86 4,4,69,867,9,5,75,76,4 4,758,669,7 4 Production: Net Capacity Cost,,97 99,964 4,45 4,987 6,5,8 7 8,964 5 Production: Capacity Related Cost Offset 6,49 64,77 6,974 4,64,764,6 5 6,7 6 Production: Non-Capacity Related Cost,7,7,55,55 5,7,96 5,74 8, ,5 7 Distribution: Demand Related Cost 979,7 979, ,65 4,849 98,59 9, (84) 8 Distribution: Customer Related Cost 8,74 8,68 9,9 5,6 7, Full Service MWH Sales,69,746,58,6,6, 7,9,67,96,55 6,556 8, 8,686 ROA MWH Sales,85,7,85,7-5,6,66, MWH Sales 7,49,87 7,,,6, 7,65,885 7,,7 6,556 8, 8,686 Customers,84,59,84,589,64,44 5,4 4,8 78

41 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Residential/Secondary RETURN (a) (b) (c) (d) (e) (f) (g) (h) (i) Total Line Rate Rate Total Rate Rate Rate GS Rate GSD Commercial No. Description Residential RT Residential GS GSD GEI GEI Secondary Total Rate Base 5,7,87 8,8 5,9,85,568,764,8, 5,6,694,9,95 Total Rate Revenue,9,684 (47),9,67 557,8 458,79, 9,94,58,8 Total Revenue Credits 7,748 7,98,47 7,559 66,4 4,75 4 Total Revenue,,4 86,,68 578,84 476,88,78,497,98,897 5 Expenses: 6 Fuel and P&I Expense 647,86,79 65,599 96,4 79,5 4,94, 9,67 7 Transmission Expense 8, ,7 5,8 45,978,88,86,556 8 Other O & M Expense 7, ,74 8,99 57,,46 4,75 47,6 9 Depreciation & Amortization Expense,,9 4, 96,7 7,78,96 5,7 76,57 Other Taxes,6 55,678 5,8 7,79,,6 66,5 Federal Income Taxes 65,7 (84) 64,8 7,895 4, ,56 Total Expenses,646,46 4,79,65,5 48,64 96,58,89 6,8 95,8 Net Operating Income 55,97 (4,67) 5,65 97,74 8, 85 4,59 8,68 4 Other Income Adjustments 4, 4 4,4, ,79 5 Adjusted Net Operating Income 6,7 (4,59) 55,479 98,949 8, , 85,46 6 Rate of Return on Rate Base 6.8% -5.5% 6.7% 6.% 6.87%.7% 4.% 6.8% 7 Index of Return (Jurisdictional) (47) Return on Rate 5.8% 6,,46 7,77 9, 68,667,97 5,848 68,596 9 Income Deficiency (Sufficiency) (5,84) 5,69 (48,) (7,89) (,58),99,58 (6,75) Revenue Deficiency (Sufficiency) (7,97) 7,55 (64,546) (,497) (6,776),8, (,4) Revenue Requirement/Total Cost of Service,9,5 7,77,98,7 567, ,5 6,59,5,76,467 Less: Revenue Credits 7,748 7,98,47 7,559 66,4 4,75 Proposed Rate Design Revenue,859,587 7,54,867,9 546,54 44,95 5,9,6,5,75 4 Production: Net Capacity Cost 4,6,445 4,45,77,889,9 6,6 4,987 5 Production: Capacity Related Cost Offset 5,6,7 6,974 7,84 65,474,88,47 4,64 6 Production: Non-Capacity Related Cost 5,789,48 5,7 57,79 4,84,98 8,45,96 7 Distribution: Demand Related Cost 54,87,9 546,65 66,89 8,4 6,6,74 4,849 8 Distribution: Customer Related Cost 9,7 9,9,8 4, ,6 9 Full Service MWH Sales,67,796 58,44,6,,7,6,9,99 88,967 87,595 7,9,67 ROA MWH Sales ,76 4,9 5,6 6,955 5,6 MWH Sales,67,796 58,44,6,,78,8,5, 4,7 5,549 7,65,885 Customers,64,44 -,64,44 9,544,, ,4

42 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Primary & Lighting RETURN (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p) Rate Rate Rate Rate Rate GPD Rate GPD Rate GPD - Total Line Rate GPD GPD GPD GP Rate GEI GEI GEI Total Rate Rate Rate Rate Lighting & No. Description GP Vlt Vlt Vlt GEI EIP Vlt Vlt Vlt Primary GML GUL GU-XL GU Unmetered Total Rate Base 8,497 4,677 7,889,8,45 49,,459 5,49 4,48 68,57,6,64 4,95 9,5 8, 6,6 Total Rate Revenue 4,57 4,48 79,779 54,8,95,8,49 5,54 9,55,,,799,4 8, 4,65 Total Revenue Credits 5, 9,856 7,485, , 45,764 55,64 8,47 4 Total Revenue 47,89 4,4 87,65 55,,744,47,74 5,77,66,77,895,854 4,45 8,5 44,79 5 Expenses: 6 Fuel and P&I Expense 6,46 5,7 5,97 6,87 9,6,479,9,965,57 67,4 48,887 4,54 8,54 7 Transmission Expense 5,49 5,845 5,85 64,56, ,89 48,48 58,7 9,6 8 Other O & M Expense,65,6 7,45 5,7,6,5 8 65,7,74 7,55 944,47 9 Depreciation & Amortization Expense 5,8 7,64,8 6,4,5,4 7 9,49 6,97 7 8,,8 9,56 Other Taxes 6,96 6,69 7,79 4,, ,66 49,567 6,85 4,77 Federal Income Taxes 5,9 (,8),6, (7) 6, 7, () 5,64 Total Expenses 8,9 9,68 79, ,4 8,489 7,,95 5,6 5,9,8,9,58 9,5 7,78 8,44 Net Operating Income 9,6 (5,98) 7, 6,88 4,55 5,45 (75) 4 5,55 95, ,9 () 8 6,59 4 Other Income Adjustments , , Adjusted Net Operating Income 9,44 (4,857) 7,68 6,45 4,98 5,454 (744) 58 5,595 98,5 49 5,68 () 89 6,456 6 Rate of Return on Rate Base.49% -.7%.7% 5.66% 8.7% 4.8% -.74%.% 8.7% 4.5% 7.6% 5.66% -.64% 4.64% 5.56% 7 Index of Return (Jurisdictional) 7 (6) (5) (6) Return on Rate 5.8% 6,9,7 9,64 6,848,859,4 5 89,979,8 87 5,4,5 6,75 9 Income Deficiency (Sufficiency) (,) 8,8,94,6 (,49) (4,49),59 68 (,65),75 (6) 4 94 Revenue Deficiency (Sufficiency) (7,587) 5,56 5,99,47 (,97) (5,556),48 9 (,6) 44,9 (8) Revenue Requirement/Total Cost of Service 9,6 75,95,56 57,458,86 6,88,59 6,68 8,5,,85,77 4, ,85 45,86 Less: Revenue Credits 5, 9,856 7,485, , 45,764 55,64 8,47 Proposed Rate Design Revenue 4,57 65,59 95,77 56,959,4 6,74,468 6,45 7,89,76,4,76,5 8,58 4,758 4 Production: Net Capacity Cost 7,95 7,978 5,8 49,57 5,45-97,4 7,56 6, ,8,8 5 Production: Capacity Related Cost Offset,498 59,7 4,85 96,464,9 4,6 84,4 4,5,764 86,444,5,6 6 Production: Non-Capacity Related Cost 48,95 9,6 88,65,684 7,668,84,59,8,98 5, ,598,58 8,75 7 Distribution: Demand Related Cost 4,94 5,58,547 56,6,464, ,897 98, ,95,55 9,589 8 Distribution: Customer Related Cost, , , Full Service MWH Sales,5,945,496,89,44,7 5,49, 85,56 8,8 44,7 54,795 5,78,96,55 4,989,65 4 9,9 6,556 ROA MWH Sales 46,5,5,8,7,7 955,479 4,79 -,86 75,46 5,985,66, MWH Sales,6,456 4,55,,66,45 6,74,6 9,5 8,8 47,6,4 45,6 7,,7 4,989,65 4 9,9 6,556 Customers, , ,

43 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 4 of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Summary Rate Base Summary (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Net Plant Production,844,4,89,788,57,6 9,448,,464, ,46 Transmission () () () () () () () () 4 Distribution 5,8,859 5,4,5,965,8,67,7 64,46 74,65 4,44 4,49 5 General/Common/Intangible 7,854 7,7 76,84 77,74,64 5,696 7,77 6 Plant Purchased/Sold 7 Total Net Plant 9,876,97 9,85,45 4,94,49,78,8,85,54,84 5,7 4,49 8 Working Capital 9 Total Current Assets,89,87,88,7 967,7 484,798 95,44 5,6 87 8,47 Total Current Liabilities,87,796,8,86 557,954 9,757,648 9, ,49 Total Working Capital 84, 799,95 49,6 9,4 8,786 5, ,6 Additions to Rate Base Deductions from Rate Base 58,4 58,,97 8,97 6,6, Adjustments to Rate Base (58,4) (58,) (,97) (8,97) (6,6) (,95) (5) (4) 5 Total Rate Base,6,697,577,84 5,9,85,9,95,6,64 6,6 5,96 45,5

44 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 5 of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Residential/Secondary Rate Base Summary (a) (b) (c) (d) - (e) (f) (g) (h) (i) Line Rate Rate Total Rate Rate Rate GS Rate GSD Commercial No. Description Residential RT Residential GS GSD GEI GEI Secondary Net Plant Production,566,6 5,87,57,6 456,865 4,67,87,879 9,448 Transmission () () () () () () () () 4 Distribution,954,747,49,965,8 94,97 6,88,79 67,9,67,7 5 General/Common/Intangible 75,757,47 76,84,9 68,79,96 5,66 77,74 6 Plant Purchased/Sold 7 Total Net Plant 4,896,64 7,49 4,94,49,47,9,,499 48,787 95,9,78,8 8 Working Capital 9 Total Current Assets 964,64,48 967,7 67,94 9,799 7,789 5,5 484,798 Total Current Liabilities 556,86, ,954 6,854 6,69 5,8 9,796 9,757 Total Working Capital 48, ,6 7,5 77,7,75 5,59 9,4 Additions to Rate Base Deductions from Rate Base,8 6,97,76 6, ,97 4 Adjustments to Rate Base (,8) (6) (,97) (,76) (6,897) (76) (748) (8,97) 5 Total Rate Base 5,7,87 8,8 5,9,85,568,764,8, 5,6,694,9,95

45 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 6 of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Primary & Lighting Rate Base Summary (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p) Rate Rate Rate Rate Rate GPD Rate GPD Rate GPD - Total Line Rate GPD GPD GPD GP Rate GEI GEI GEI Total Rate Rate Rate Rate Lighting & No. Description GP Vlt Vlt Vlt GEI EIP Vlt Vlt Vlt Primary GML GUL GU-XL GU Unmetered Net Plant Production 4,69 99,6 7,59 58,5,87,46,997 7,686 8,7,,464 48,57 7,97,87 Transmission () () () () () () () () () () () () () () () 4 Distribution,4 4,747 7,846 58,6,46 8, ,5,55 64,46,77 6, ,85 74,65 5 General/Common/Intangible 5,8,87,7 6,,7,7 7 88,787, ,8,6 5,696 6 Plant Purchased/Sold 7 Total Net Plant 59,894 65,95 9,977,,66 45,977 9,75 5,,555 64,5,85,54 4,559 8,44 6,8,84 8 Working Capital 9 Total Current Assets 47,47 74,444 6,944 84,599 7,96 4,8 9,47,4 95,44,6,98 4,4 5,6 Total Current Liabilities 5,897 8,594,9,5 4,474,987 57,47 6,49, ,,774 9,485 Total Working Capital,5 5,85 8,75 8,84,45, ,755 8,786 48,869,67 5,677 Additions to Rate Base Deductions from Rate Base , ,6 47,6 87,95 4 Adjustments to Rate Base (96) (68) (84) (,4) (5) (8) (6) (57) (9) (6,6) (47) (,6) () (87) (,95) 5 Total Rate Base 8,497 4,677 7,889,8,45 49,,459 5,49 4,48 68,57,6,64 4,95 9,5 8, 6,6

46 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 7 of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Summary O&M Summary (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Production Fuel Expense 5, 54,56 95,987,7 4,4, ,749 Purchased & Interchange Power Expense,54,45,4,4 454,6 69,884 4,59 5,78 47,74 4 Total Fuel and P&I Expense,684,76,667,8 65,599 9,67 67,4 8, ,9 5 Fossil O&M Exp 4,456, 44,7 6, 4, ,56 6 Nuclear O&M Exp 7 Hydro O&M Exp 4,499 4,59 5,77,79 5, Peaker O&M Exp 7,78 7,44 5,449 8,977, Other O&M 9,874 9,786 4,8,46,69 88 Total Prod O&M Exp 76,68 74,887 69,45 4,5 6, ,7 Total Prod O&M Expense Including Fuel and P&I,86,5,84,69 7,5 4,6 68,97 9,5 78 8,645 Trans and Dist O&M Trans O&M Exp 49,64 45,4 8,7,556 48,48,6 87 4,9 4 Other O&M Adjustments 5 Distr Oper Exp 65,9 65,95 7,79 6,6 4,8 6, Distr Maint Exp 7,95 7,95 66,447 8,98,96, 68 7 Total T&D Expense 6,498 69, 87,5 56,844 64,44,65 8 4,65 8 Customer Related O&M 9 Customer Accounts Exp 4,48 4,48 8,7 5,7 6 5 Customer Service Exp 7,688 7,6,6,9, Sales Expense Total Customer Expense 5, 5,4 4,89 6,5, Admin & General Expense 7,475 7,87 9,76 44,55,8 4, Total Electric O&M Expense,78,49,684,85,4,4 69,56 877,8 4,57 987,574 //9 :

47 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 8 of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Residential/Secondary O&M Summary (a) (b) (c) (d) - (e) (f) (g) (h) (i) Line Rate Rate Total Rate Rate Rate GS Rate GSD Commercial No. Description Residential RT Residential GS GSD GEI GEI Secondary Production Fuel Expense 95, ,987 6,95 55,56,474,4,7 Purchased & Interchange Power Expense 45,75,86 454,6 5,46 4,96,468 6,858 69,884 4 Total Fuel and P&I Expense 647,86,79 65,599 96,4 79,5 4,94, 9,67 5 Fossil O&M Exp 44,5 9 44,7,, , 6 Nuclear O&M Exp 7 Hydro O&M Exp 5,74 5,77,694, ,79 8 Peaker O&M Exp 5,9 58 5,449 4,49 4, ,977 9 Other O&M 4, 5 4,8,74,8 59,46 Total Prod O&M Exp 69, ,45,567 8,88 5, 4,5 Total Prod O&M Expense Including Fuel and P&I 76,97,8 7,5 6,979 98,5 5,465, 4,6 Trans and Dist O&M Trans O&M Exp 8, ,7 5,8 45,978,88,86,556 4 Other O&M Adjustments 5 Distr Oper Exp 7,7 9 7,79 9,774 5, ,6 6 Distr Maint Exp 66,4 4 66,447,9 4,48 79,56 8,98 7 Total T&D Expense 86,74,6 87,5 8,94 66,45,487 5,9 56,844 8 Customer Related O&M 9 Customer Accounts Exp 8,7-8,7 4, ,7 Customer Service Exp,59 9, ,9 Sales Expense Total Customer Expense 4,8 9 4,89 5,6, ,5 Admin & General Expense 9,5 6 9,76 5,4 7, 759,456 44,55 4 Total Electric O&M Expense,7,65 4,49,4,4,89 8,5 8,767 7,567 69,56 //9 :

48 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 9 of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Primary & Lighting O&M Summary (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p) Rate Rate Rate Rate Rate GPD Rate GPD Rate GPD Line Rate GPD GPD GPD GP Rate GEI GEI GEI Total Rate Rate Rate Rate Lighting & No. Description GP Vlt Vlt Vlt GEI EIP Vlt Vlt Vlt Primary GML GUL GU-XL GU Unmetered Production Fuel Expense 9,8 5,89 5,48 8,58,98 5, ,95 4,4 9,76,466,446 Purchased & Interchange Power Expense 4,8 98,8 69,85 77,54 6,8 6,78,8,5 8,68 4,59 64,6,688 5,78 4 Total Fuel and P&I Expense 6,46 5,7 5,97 6,87 9,6,479,9,965,57 67,4 48,887 4,54 8,54 5 Fossil O&M Exp 4,9,7 7, 7, , Nuclear O&M Exp 7 Hydro O&M Exp 56,8 875, , Peaker O&M Exp,9,945, 5, , Other O&M , ,69 9 Total Prod O&M Exp 6,9 5,6,788 7,56 954,88 99, 6, Total Prod O&M Expense Including Fuel and P&I 67,78 66,8 6,85 88,8,9,568,,87,88 68, ,54 4,57 9,5 Trans and Dist O&M Trans O&M Exp 5,49 5,845 5,85 64,56, ,89 48,48 58,7 9,6 4 Other O&M Adjustments 5 Distr Oper Exp , ,8 9 6, ,978 6 Distr Maint Exp,86 5,8 6, ,96 79,5 8, 7 Total T&D Expense 8,7 6,54 6,85 74,5, , 64, ,,84,65 8 Customer Related O&M 9 Customer Accounts Exp Customer Service Exp , Sales Expense - - Total Customer Expense , , Admin & General Expense,7 5,94 4,5 4, ,8, , 4 Total Electric O&M Expense 89,94 8,7 48,8 77,767 4,,99,64 4,44 8, ,8, 7, 6,9 4,57 //9 :

49 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Summary Allocators (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Input Allocation Schedules Generation Energy Generation Energy Generation Energy Generation Summer Energy Generation Summer Energy Generation Non-Summer Energy Generation Non-Summer Energy Critical Gen Energy Summer Gen CP Generation CP Generation Class Subtransmission Transmission Total Rate Revenue Billed Sales Billed Sales Excluding Rate E Number Of Customers Weighted Customer Calculated Allocation Schedules 9 4CP Average & Excess CP 75// CP 75//5 Exc WFR CP Gen Jurisdictional CP Subtrans Primary Secondary Classpeak for Streetlighting Single Phase Billed Sales ROA Billed Sales - Primary Customers - Residential Customers - Drops Customers - NonPID Customers - NonMunicipal PIS - 8kV Distribution PIS - 46kV Distribution PIS - 8kV Dist Subs S&E PIS - 46kV Dist Subs S&E

50 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Residential/Secondary Allocators (a) (b) (c) (d) - (e) (f) (g) (h) (i) Line Rate Rate Total Rate Rate Rate GS Rate GSD Commercial No. Description Alloc Residential RT Residential GS GSD GEI GEI Secondary Input Allocation Schedules Generation Energy Generation Energy Generation Energy Generation Summer Energy Generation Summer Energy Generation Non-Summer Energy Generation Non-Summer Energy Critical Gen Energy Summer Gen CP Generation CP Generation Class Subtransmission Transmission Total Rate Revenue Billed Sales Billed Sales Excluding Rate E Number Of Customers Weighted Customer Calculated Allocation Schedules 9 4CP Average & Excess CP 75// CP 75//5 Exc WFR CP Gen Jurisdictional CP Subtrans Primary Secondary Classpeak for Streetlighting Single Phase Billed Sales ROA Billed Sales - Primary Customers - Residential Customers - Drops Customers - NonPID Customers - NonMunicipal PIS - 8kV Distribution PIS - 46kV Distribution PIS - 8kV Dist Subs S&E PIS - 46kV Dist Subs S&E

51 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Primary & Lighting Allocators (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p) Rate Rate Rate Rate Rate GPD Rate GPD Rate GPD Line Rate GPD GPD GPD GP Rate GEI GEI GEI Total Rate Rate Rate Rate Lighting & No. Description Alloc GP Vlt Vlt Vlt GEI EIP Vlt Vlt Vlt Primary GML GUL GU-XL GU Unmetered Input Allocation Schedules Generation Energy Generation Energy Generation Energy Generation Summer Energy Generation Summer Energy Generation Non-Summer Energy Generation Non-Summer Energy Critical Gen Energy Summer Gen CP Generation CP Generation Class Subtransmission Transmission Total Rate Revenue Billed Sales Billed Sales Excluding Rate E Number Of Customers Weighted Customer Calculated Allocation Schedules 9 4CP Average & Excess CP 75// CP 75//5 Exc WFR CP Gen Jurisdictional CP Subtrans Primary Secondary Classpeak for Streetlighting Single Phase Billed Sales ROA Billed Sales - Primary Customers - Residential Customers - Drops Customers - NonPID Customers - NonMunicipal PIS - 8kV Distribution PIS - 46kV Distribution PIS - 8kV Dist Subs S&E PIS - 46kV Dist Subs S&E

52 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Summary Allocators (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) Total Total Total Total Line Total Jurisdictional Total Commercial Total Lighting & Rate Non No. Description Alloc Electric Electric Residential Secondary Primary Unmetered GSG Jurisdictional Calculated Allocation Schedules PIS - Overhead Primary System (.) PIS - Distribution Distribution Overhead Distribution Underground Distribution (.) 5 Total Dist PIS Distribution Services Streetlighting Equipment Line Equipment Meters PIS - System Power Control (99.6) PIS - General Total PIS Distribution Depreciation CWIP Working Capital Rate Base Operations - Distribution excl Sup & Eng Maintenance - Distribution excl Sup & Eng Operations - 8kV Distribution excl Sup & Eng Maintenance - 8kV Distribution excl Sup & Eng Operations - 46kV Distribution excl Sup & Eng Maintenance - 46kV Distribution excl Sup & Eng HV Distribution O&M exp Distribution O&M, excl. HV Dist Customer Accounting Customer Accounts & Service Distribution O&M Customer & Sales O&M Administrative and General O&M Jurisdictional Distribution O&M O&M Excluding Adjustments Pre Tax NOI (.46) R&PP Tax Depreciation & Amortization Expense Non PSCR O&M Expense Distribution Depreciation Expense Gen/Comm/Int Depreciation Expense Production Labor Total Labor % O&M, 5% Net Plant /5 PIS & Labor

53 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 4 of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Residential/Secondary Allocators (a) (b) (c) (d) - (e) (f) (g) (h) (i) Line Rate Rate Total Rate Rate Rate GS Rate GSD Commercial No. Description Alloc Residential RT Residential GS GSD GEI GEI Secondary Calculated Allocation Schedules PIS - Overhead Primary System PIS - Distribution Distribution Overhead Distribution Underground Distribution Total Dist PIS Distribution Services Streetlighting Equipment Line Equipment Meters PIS - System Power Control PIS - General Total PIS Distribution Depreciation CWIP Working Capital Rate Base Operations - Distribution excl Sup & Eng Maintenance - Distribution excl Sup & Eng Operations - 8kV Distribution excl Sup & Eng Maintenance - 8kV Distribution excl Sup & Eng Operations - 46kV Distribution excl Sup & Eng Maintenance - 46kV Distribution excl Sup & Eng HV Distribution O&M exp Distribution O&M, excl. HV Dist Customer Accounting Customer Accounts & Service Distribution O&M Customer & Sales O&M Administrative and General O&M Jurisdictional Distribution O&M O&M Excluding Adjustments Pre Tax NOI (.74) R&PP Tax Depreciation & Amortization Expense Non PSCR O&M Expense Distribution Depreciation Expense Gen/Comm/Int Depreciation Expense Production Labor Total Labor % O&M, 5% Net Plant /5 PIS & Labor

54 MICHIGAN PUBLIC SERVICE COMMISSION Consumers Energy Company Electric Cost-of-Service Study Schedule F-. Case No.: U-4 Exhibit No.: S-6 (SEG-) Schedule: F-. Page: 5 of 5 Witness: SEGoepp Date: September 7, 8 Projected -Month Period Ending Dec, 9 Version 4CP 75//5 Production and CP Transmission (thousands of dollars) Primary & Lighting Allocators (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p) Rate Rate Rate Rate Rate GPD Rate GPD Rate GPD Line Rate GPD GPD GPD GP Rate GEI GEI GEI Total Rate Rate Rate Rate Lighting & No. Description Alloc GP Vlt Vlt Vlt GEI EIP Vlt Vlt Vlt Primary GML GUL GU-XL GU Unmetered Calculated Allocation Schedules PIS - Overhead Primary System PIS - Distribution Distribution Overhead Distribution Underground Distribution Total Dist PIS Distribution Services Streetlighting Equipment Line Equipment Meters PIS - System Power Control PIS - General Total PIS Distribution Depreciation CWIP Working Capital Rate Base Operations - Distribution excl Sup & Eng Maintenance - Distribution excl Sup & Eng Operations - 8kV Distribution excl Sup & Eng Maintenance - 8kV Distribution excl Sup & Eng Operations - 46kV Distribution excl Sup & Eng Maintenance - 46kV Distribution excl Sup & Eng HV Distribution O&M exp Distribution O&M, excl. HV Dist Customer Accounting Customer Accounts & Service Distribution O&M Customer & Sales O&M Administrative and General O&M Jurisdictional Distribution O&M O&M Excluding Adjustments Pre Tax NOI (.45) (.8) (.) R&PP Tax Depreciation & Amortization Expense Non PSCR O&M Expense Distribution Depreciation Expense Gen/Comm/Int Depreciation Expense Production Labor Total Labor % O&M, 5% Net Plant /5 PIS & Labor

55 Annual Report Case No. U-4 MPSC Form P-5 Exhibit S-7. Generating Plant Statistics Witness S. Goepp Page: of ('s) ('s) ('s) ('s) Base Load Total Cost Total Cost Total Cost Total Cost Campbell & $766,54 $759,5 $767,6 $,4,79 Cobb 4-5 $,5 $54 $9 $8 Whiting $78,84 $489 $5 $58 Karn & $68,48 $979,6 $,75, $,76,869 Weadock 7 & 8 $79, $,67 $,84 $,956 Campbell -9.% $,7,88 $,76, $,77,478 $,647,655 Hardy $4,45 $4,47 $4,57 $4,9 Hodenpyl $9,464 $9,464 $9,467 $9,75 Tippy $8,8 $8,858 $8,85 $9,65 Total Base Load $,,69 $,85,89 $,956,675 $,868,888 Other Than Base Load Karn & 4 $,776 $,44 $,648 $,97 B C Cobb - $4,988 $ $ $ Zeeland $,95 $65,9 $66,44 $8,46 Foote $4,6 $4,67 $7,7 $7,54 Cooke $,67 $,68 $,76 $,87 Five Channels $4,55 $5,84 $5,47 $5,48 Loud $,4 $,44 $,44 $,99 Alcona $4, $,965 $4,5 $5,5 Mio $5,69 $5,669 $6,4 $6,8 Croton $,5 $,8 $,77 $,89 Rogers $8,75 $8,8 $8, $8,67 Webber $8,46 $8,7 $8,797 $,84 Calkins Bridge $,6 $,44 $,94 $5,56 Lake Winds Energy Park $,67 $,87 $,5 $5,5 Ludington-5% $9,876 $9,9 $44,974 $9,4 Weadock $,6 $,67 $,6 $,6 Thetford $,54 $,69 $,9 $,795 Whiting $,76 $,76 $,76 $,78 Morrow $,47 $ $ $ Gaylord $6,7 $4,865 $5,56 $5,77 Straits $,55 $,49 $,99 $,99 Campbell $,75 $,75 $,787 $,788 Cross Winds $ $47,964 $7,7 $4,64 GVSU Solar $ $ $ $7,65 WMU Solar $ $ $ $4,5 Total other $,54,8 $,4, $,47,97 $,5,677 Grand total, all generating units $4,65,496 $4,7,849 $4,47,6 $5,4,565 9/5/8 :6

56 Case No. U-4 Analysis of Load Data in COSS Study Exhibit S-7. Without ROA Witness S. Goepp Page: of U-4 U-4 U-4 U Total KWh for the year w/o ROA,877,76,649,5,5,94,684,467,8 4,79,97,549 COSS Minimum hour for the year,565,94,76,54,64,7,656,8 876 Average energy per hour,75,66,8,8,845,59,879,7 avg max/min Min as % of avg 68.4% 7.9% 68.8% 68.5% Maximum hour 7,55,965 6,595,8 7,7,87 6,8,44 COSS Min hr as a % of Max hr 4.% 4.5% 7.4% 4.% Total Base load Cost $,,69 $,85,89 $,956,675 $,868,888 MPSC P-5 Total Cost of all Generating Units 4,65,496 $ 4,7,849 $ 4,47,6 $ 5,4,565 MPSC P-5 Base Load as a percent of total 7.9% 66.7% 66.8% 7.6% Base Load as a percent of Max Load 4.% 4.5% 7.4% 4.% Percent to be allocated on Energy 4.8% 7.7% 5.%.% 7.% AVERAGE OF - 6 U-4 4.5% AVERAGE OF 9 - U-8 Note: Total kwh for the year is per COSS Load Data tab- "Sales" lines, 5, 85, 6 column AW Minimum Hour for the year is per 876 data Average energy per hour is calculated from the Total kwh/876 in all cases Min as a % of avg compares minimum hour to average hour- calculation Maximum hour is per COSS Load Data tab- lines 7, 49, 8, column AW Min as a % of Max hr compares minimum hour to maximum hour- calculation Total Base Load Cost and Total Cost of Generating units are based on Annual Report MPSC P /5/8 :6

57 S T A T E OF M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * In the matter of the application of ) Consumers Energy Company ) for authority to increase its rates for ) Case No. U-4 the generation and distribution of ) electricity and for other relief ) ) QUALIFICATIONS AND DIRECT TESTIMONY OF STACY A. HARRIS MICHIGAN PUBLIC SERVICE COMMISSION September, 8

58 QUALIFICATIONS OF STACY A. HARRIS CASE NUMBER U-4 PART I Q. Please state your name and business address. A. My name is Stacy A. Harris and my business address is 79 West Saginaw Highway, Lansing, MI 4897 Q. By whom are you employed, and what is your present position? A. I am employed by the Michigan Public Service Commission (MPSC or Commission) as an Auditor in the Regulated Energy Division, Revenue Requirements Section. Q. How long have you been employed by the Commission? A. Since October of 6. Q. What is your educational and professional background? A. In 5, I graduated from Walsh College with a Master of Science Degree in Accountancy. In, I graduated from Michigan State University with a Bachelor of Art Degree in Economics. In 8, I graduated from Monroe Community College in Rochester, NY with an Associate of Science Degree in Business Administration. Prior to coming to work for the Commission, I was employed by Michigan State University, Facility for Rare Isotope Beams (FRIB), as an Accounting Clerk II. While employed at the FRIB, I was responsible for reviewing expenses for compliance and for the reconciliation of the FRIB financial accounts. I was also previously employed by Lansing East Lodging as a General Manager for Red Roof Inn. As General Manager, I was responsible for managing all of the operational and financial functions of the hotel.

59 QUALIFICATIONS OF STACY A. HARRIS CASE NUMBER U-4 PART I Q. Have you previously sponsored testimony before the Michigan Public Service Commission? A. Yes. I have sponsored testimony in the following cases: Case Number Company Case Type U-844 Consumers Energy Co. Gas Rate Case U-84 DTE Electric and Gas Co. Billing and shut-off practices

60 DIRECT TESTIMONY OF STACY A. HARRIS CASE NUMBER U-4 PART II Q. What is the purpose of your testimony? A. The purpose of my testimony is to present MPSC Staff s ( Staff ) total projected rate base for the -month ending December, 9 ( projected test year ) in the instant Consumers Energy Company ( Consumers Energy or the Company ) electric rate case. Additionally, I will be supporting ) The Working Capital Summary presented in Staff Exhibit S-, Schedule B-4, ) adjustments on Staff Exhibit S-, Schedule C-, sponsored by Staff witness Nichols, to the Company s projected depreciation expense and property tax expense, and ) adjustments on Staff Exhibit S-, Schedule C-5, sponsored by Staff witness Welke, to the Company s projected Employee Incentive Compensation Plan. Q. Are you sponsoring any exhibits in this proceeding? A. Yes, I am sponsoring the following exhibits: S- Schedule B-: Projected Rate Base for Test Year Ending December, 9 S- Schedule B-4: Working Capital Summary 5 S-8. Company Response (#7) to U-844 MPSC Audit Request: SAH Q. Were these exhibits prepared by you or under your direction? A. Yes. Rate Base Q. What is the total rate base being presented by Staff in the instant case for projected test year? A. Referring to Staff Exhibit S-, Schedule B-, Line 7, Column (f), Staff presents a total company basis projected rate base of $,6,696,. This is a decrease of $9,6, from the Company s $,75,, projection on Exhibit A-

61 DIRECT TESTIMONY OF STACY A. HARRIS CASE NUMBER U-4 PART II (HJM-4), Schedule B-, Line 7, Column (c), in its initial filing. My testimony below will address the individual components resulting in the $9,6, reduction to the Company s filed rate base. Utility Plant and Depreciation Reserve: Q. What is the total projected utility plant being presented by Staff for the projected test year? A. Referring to Staff Exhibit S-, Schedule B-, Line, column (f), Staff presents total company basis projected utility plant of $5,76,9,. This is a decrease of $95,8, from the Company s $5,8,85, projection presented on Exhibit A- (HJM-4), Line, Column (c), in its initial filing. Q. Please explain the $95,8, difference. A. The $95,8, difference is a direct result of adjustments made by Staff to the Company s projected capital expenditures. A summary of those adjustments as well as the corresponding Staff witness supporting each adjustment is illustrated in Figure below. 6 4

62 DIRECT TESTIMONY OF STACY A. HARRIS CASE NUMBER U-4 PART II Q. What is the projected depreciation reserve being presented by Staff for the projected test year? A. Referring to Staff Exhibit S-, Schedule B-, Line, Column (f), Staff presents a total company basis projected depreciation reserve of $5,859,9,. This is a decrease of $,56, from the Company s $5,86,598, projection presented on Exhibit A- (HJM-), Schedule B-, Line, Column (c), in its initial filing. Q. Please explain the $,56, difference. A. The $,56, difference is a direct result of adjustments made by Staff to the Company s projected capital expenditures. A summary of those adjustments, as well as the corresponding Staff witness supporting each adjustment, appears in Figure, above. Working Capital Q. What is the projected working capital being presented by Staff for the projected test year? A. Referring to Staff Exhibit S-, Schedule B-, Line 6, Column (f), Staff presents total company basis working capital of $84,,. This is the same amount the Company presented on Exhibit A- (HJM-4), Schedule B-, Line 6, Column (c), in its initial filing. The derivation of working capital is presented on Staff Exhibit S-, Schedule B-4, Working Capital Summary. Depreciation Expense Adjustment Q. The Company provides a projected amount for depreciation and amortization expense of $655,49, on its Exhibit A- (HJM-49), Schedule C-, in its initial filing, is that correct? 5

63 DIRECT TESTIMONY OF STACY A. HARRIS CASE NUMBER U-4 PART II A. Yes. Q. What adjustment to the Company s projected depreciation expense are you supporting? A. I am supporting an adjustment on Exhibit S-, Schedule C-, sponsored by Staff witness Nichols, to decrease the Company s total company basis projected depreciation by $4,785, to $65,64,. This adjustment is a direct result of Staff adjustments to the Company s projected capital expenditures illustrated in Figure of my testimony. Property Tax Expense Adjustment Q. What adjustment to the Company s projected property tax expense are you supporting? A. I am supporting an adjustment on Exhibit S-, Schedule C-, sponsored by Staff witness Nichols, to decrease the Company s total company basis projected property tax expense by $,64,. Q. How did you derive the $,64,? A. I used the Company s property tax rate of.% from its Exhibit A-4 (BJV-) and multiplied that rate by the test year average plant in service impact illustrated in Figure of my testimony. Q. Why did Staff incorporate this adjustment as part of the test year impacts from Staff adjustments to the Company s historic and projected capital expenditures? A. The Company s projected property tax expense is developed, in part, by using its projected plant balances. Since Staff s capital expenditure adjustments result in a 6

64 DIRECT TESTIMONY OF STACY A. HARRIS CASE NUMBER U-4 PART II decrease to the Company s projected test year plant balance, a corresponding adjustment is needed to decrease the projected test year property tax expense. Employee Incentive Compensation Plan (EICP) Expense Q. What is Employee Incentive Compensation Plan expense? A. Employee Incentive Compensation Plan expense is a portion of an employee s pay that is dependent upon achieving target levels on performance measures. Q. Has the Company requested recovery of EICP expense in this case? A. Yes. Q. What are the performance measures of the Company s EICP? A. Exhibit A-7 (AMC-) outlines the Company s performance measures. The measures are broken into two categories: operational and financial. There are nine performance measures in the operational category and two performance measures in the financial category. Q. How do employees earn EICP? A. Employees earn EICP by achieving target levels in each performance measure. Examples of target levels found on Exhibit A-7 (AMC-) are achieving greater than or equal to 9% in records accuracy and achieving a customer experience index of greater than or equal to 5. Six of the nine operational and both financial performance measures listed on that exhibit need to be achieved at target level to earn % of the proposed EICP expense requested for recovery in this case. The required financial targets consist of an earnings per share at $. and an operating cash flow of $.65 billion. All non-union employees are eligible for EICP incentives, except for employees rated as under contributing or 7

65 DIRECT TESTIMONY OF STACY A. HARRIS CASE NUMBER U-4 PART II moderate on their annual performance appraisal. Both non-officers and officers participate in an annual EICP. Q. Does Staff support the Company s EICP expense in rates? A. No. A portion of the plan relates to financial based performance measures, which has been repeatedly excluded from the revenue requirement by the Commission in the following cases: -Case No. U-447, //5 Order, (Consumers Energy electric rate case) -Case No. U-4547, //6 Order, (Consumer Energy gas rate case) -Case No. U-545, 6//8 Order, (Consumers Energy electric rate case) -Case No. U-544, //8 Order, (Detroit Edison electric rate case) -Case No. U-5645, //9 Order, (Consumers Energy electric rate case) -Case No. U-598, 7// Order, (Wisconsin Electric Power electric rate case) -Case No. U-5768, // Order, (Detroit Edison electric rate case) -Case No. U-647, // Order, (Detroit Edison electric rate case) -Case No. U-775, /9/5 Order, (Consumers Energy electric rate case) -Case No. U-84, 7//7 Order, (Consumers Energy gas rate case) -Case No. U-8, /9/8 Order, (Consumers Energy electric rate case) Q. Why did the Commission exclude the portion of EICP related to financial based performance measures from the revenue requirement in the above referenced cases? A. The Commission s decision to exclude incentive compensation related to financial measures from the revenue requirement in preceding rate cases was founded on two premises. First, the Commission found that incentive 8

66 DIRECT TESTIMONY OF STACY A. HARRIS CASE NUMBER U-4 PART II compensation plans that were tied to Company earnings and cash flow were financial considerations that largely benefited shareholders and should not be paid for by ratepayers. See MPSC case No. U-447, Opinion and Order, December, 5, p 5. Second, the Commission has repeatedly found that utilities did not sufficiently quantify the benefits to ratepayers of employee incentive compensation plans that are tied to non-financial metrics and demonstrate that the benefits to customers of such plans outweigh the costs. See MPSC Case No. U- 544, Opinion and Order, December, 8, p 8. Q. What amount of EICP has Staff included in its case? A. As shown on Staff Exhibit S-, Schedule C-5, sponsored by Staff witness, Welke, Staff has included only the portion relating to the achievement of non-financial goals, or $,74,. (See Staff Exhibit S-8., Company Response (#7) to U- 844 MPSC Audit Request: SAH-6). Q. Does this conclude your testimony? A. Yes. 9

67 S T A T E OF M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * In the matter of the application of ) Consumers Energy Company ) for authority to increase its rates for ) Case No. U-4 the generation and distribution of ) electricity and for other relief ) ) EXHIBITS OF STACY A. HARRIS MICHIGAN PUBLIC SERVICE COMMISSION September, 8

68 Schedule B- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S- Projected Rate Base Schedule: B- Projected Month Period Ending December, 9 Page: of ($) Witness: SAHarris (a) (b) (d) (e) (f) (g) Line Applicant Staff Staff Staff No. Description Source Projection Adjustment Projection Jurisdictional Total Utility Plant Exhibit: A- (HJM-44) $ 5,8,85 $ (95,8) $ 5,76,9 $ 5,67,54 Depreciation Reserve Exhibit: A- (HJM-45) 5,86,598 (,56) 5,859,9 $ 5,85,69 Net Utility Plant Line - Line $ 9,969,5 $ - $ 9,876,97 $ 9,85,45 4 Retainers & Customer Advances Exhibit: A- (HJM-4) (58,4) - (58,4) (58,) 5 Adjusted Net Utility Plant Sum Lines - 4 9,9, - 9,88,685 9,777, 6 Working Capital Exhibit: A- (HJM-46) 84, - 84, 799,95 7 Total Projected Period Rate Base Line 5 + Line 6 $,75, $ (9,6) $,6,696 $,577,84

69 Schedule B-4 MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S- Working Capital Summary Schedule: B-4 Projected Month Period Ending December, 9 Page: of ($) Witness: SAHarris (a) (b) (c) (d) Line Applicant Staff Staff No. Description Projection Adjustment Projection Assets Cash $ 58,44 $ - $ 58,44 Accounts Receivable 98,7-98,7 Sale of Receivables CE Receivable Funding Materials & Supplies 88,5-88,5 6 Fuel Stock 67,8-67,8 7 Clean Air Allowance Accrued Revenues 4,48-4,48 9 Sale of Accrued Revenues Prepayments,5 -,5 Real & Personal Property Taxes 79,8-79,8 Deferred Debits 854, ,469 Total Assets,89,87 -,89,87 Liabilities 4 Accounts Payable 94,8-94,8 5 Customer Deposits 7,74-7,74 6 Dividends Payable,56 -,56 7 Accrued Interest 44,46-44,46 8 Accrued Taxes 65, - 65, 9 Other Current Liabilities,66 -,66 Deferred Credits and Operating Reserves 45,4-45,4 Total Liabilities,87,796 -,87,796 Total Projected Working Capital $ 84, $ - $ 84, Source Column (b): Exhibit: A- (HJM-6) Column (c): Column (d) - Column (b) Column (d): Exhibit: A- (HJM-47) Column (e): Column (f) - Column (d) Column (f): Exhibit: A- (HJM-47)

70 Consumers Energy Company Case No. U-4 Exhibit S-8. Page of Witness: SAHarris Request #: 7 Page of MPSC AUDIT REQUEST CASE NO: U-4 DATE OF REQUEST: 5/5/8 NO. SAH-6 REQUESTED BY: Stacy A. Harris DATE OF RESPONSE: 5/6/8 RESPONDENT: Amy M. Conrad Question:. Relating to incentive compensation, if no financial metrics are achieved and all other non-financial metrics are achieved at target, what would the total officer and non-officer projected test year payout be? (Only the amount to be reflected in the revenue requirement.) Answer: Assuming % target payout of the operating performance measures and no financial measures achieved, the rate request in Exhibit A-7 (AMC-) would be as follows: Item Projected Test Year (In millions) Incremental Incentive Compensation O&M Expense Annual Incentive - Officer $ - Annual Incentive - Non Officer (EICP).74 TOTAL $.74

71 S T A T E OF M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * In the matter of the application of ) CONSUMERS ENERGY COMPANY ) for authority to increase its rates for ) Case No. U-4 the generation and distribution of ) electricity and for other relief. ) ) QUALIFICATIONS AND DIRECT TESTIMONY OF DAVID W. ISAKSON MICHIGAN PUBLIC SERVICE COMMISSION September, 8

72 QUALIFICATIONS OF DAVID W ISAKSON CASE NUMBER U-4 PART I Q. Please state your name, address, and current position. A. My name is David W. Isakson. My business address is 79 West Saginaw Hwy, Lansing, Michigan I am currently employed by the Michigan Public Service Commission (MPSC or Commission) in the Rates and Tariff Section of the Regulated Energy Division as a Departmental Analyst. Q. Would you briefly describe your educational background? A. I received a B.S. in economics from Central Michigan University in August 8. In, I completed an M.A. in economics at Central Michigan University. Q. Have you attended any seminars or other training courses? A. Yes. In August, I completed the National Association of Regulatory Utility Commissioners (NARUC) Annual Regulatory Studies Program held at Michigan State University. In October, I attended the Association of Edison Illuminating Companies Advanced Load Research Seminar in Columbus, Ohio. Q. What are your responsibilities in your current position? A. I participate in rate, Time Interest Earned Ratio (TIER), tariff amendment, and special contract cases under the supervision of the Rates and Tariff manager. My duties also involve performing research in special topics such as rate benchmarking, load research, demand response, and the economics of public utility regulation. Q. Have you previously presented testimony or participated in utility cases before the MPSC? A. Yes, I have participated in the following cases:

73 QUALIFICATIONS OF DAVID W ISAKSON CASE NUMBER U-4 PART I MPSC Case Company Description U-647-R Ontonagon County REA TIER Rate Design, Auditing U-6855 Consumers Energy Company SI Rate Reconciliation U-76 Indiana Michigan Power Company Tariff Review U-788 Indiana Michigan Power Company Tariff Review U-74 DTE Electric Company Tariff Review U-7 Consumers Energy Company Tariff Review U-74 DTE Gas Company UETM Reconciliation U-744 Consumers Energy Company SI Rate Reconciliation U-747 DTE Electric Company PLD Transition Plan U-7-R Thumb Electric Cooperative TIER Rate Design, Auditing U-764 Consumers Energy Company Gas Rate Design U-7767 DTE Electric Company Electric Rate Design U-776 DTE Electric Company PLD Trans. Reconciliation U-7999 DTE Gas Company Gas Cost of Service Study U-85 DTE Electric Company PLD Trans. Reconciliation U-84 DTE Electric Company Electric Rate Design, RDM U-84 Consumers Energy Company Gas Cost of Service Study U-8 Consumers Energy Company Electric Rate Design U-844 Consumers Energy Company Gas Cost of Service Study U-8999 DTE Gas Company Gas Cost of Service Study

74 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II Q. What is the purpose of your testimony? A. The purpose of my testimony is to present MPSC Staff s (Staff) positions on rate design, tariff amendments, and certain issues pertaining to demand response. Q. Are you sponsoring any exhibits? A. Yes. I am sponsoring the following exhibits: Staff Exhibit S-6, Schedule F-, Staff Summary of Present and Proposed Revenue by Rate Schedule Staff Exhibit S-6, Schedule F-., Staff Calculation of Rate Design Targets Staff Exhibit S-6, Schedule F-., Staff Summary of Updated Present Revenue by Rate Schedule Staff Exhibit S-6, Schedule F-, Staff Present and Proposed Revenue Detail Staff Exhibit S-7 Staff Audit Response #86. Q. How does Staff perform its rate design? A. Rates are designed to collect the revenue requirement proposed by Staff as allocated in Staff s cost of service study (COSS) presented by Staff witness Susan Goepp. Rate design begins with an audit of the Company s filed rate design and involves verifying present rates, billing determinants, and formulas used to calculate proposed rates. Next, adjustments are made to the rate design model to reflect Staff s rate design positions as described later in my direct testimony. Finally, revenue requirements by rate class are imported from the COSS model and the resulting proposed rates are calculated and reviewed for reasonableness and error. Present Revenue

75 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II Q. Does Staff have any adjustments to present rates as filed by the Company? A. Yes. The Company filed its application in the instant case on May 4, 8. The present rates used by Company witness Laura M. Collins in her rate design shown in Company Exhibit A-6, Schedule F- represent the Company s rates at that time. The present revenue shown in Company Exhibit A-6, Schedule F-, column B, and the total increase/decrease in columns D and E all reflect base rates as of May 4. In the months following the Company s application, the Commission issued two orders affecting base rates and one order implementing a credit to reflect tax savings resulting from the Tax Cuts and Jobs Act of 7 (TCJA). First, on June, 8 the Commission issued an errata order in the Company s previous rate case MPSC Case No. U-8. The errata order only affected base rates for primary customers. On June 8, 8, the Commission issued a rehearing order in the same case that adjusted the total revenue requirement from the amount initially approved in its March 9, 8 order. To most accurately reflect present rates in the test year of the instant case, the results of the two aforementioned orders must be incorporated in the rate design model. Staff s rate design model, shown on Staff Exhibit S-6, F-, is updated to include present base rates as of Staff s filing. The result of this update is an increase in present revenue of $.4M, as shown in Staff Exhibit S-6, Schedule F-., column D, line 6. The increase in present revenue reduces the Company s revenue deficiency by the same amount. Q. How did Staff calculate the effects of the expiration of the TCJA Credit A? 4

76 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II A. Staff included the Credit A rates as a component of present revenue for each affected rate as shown on Exhibit S-6, Schedule F-. The credit is multiplied by the test year billing determinants for each rate and then summed to arrive at a total of $.4M. Q. How does the expiration of the TCJA Credit A affect the net rate increase proposed by Staff? A. The TCJA Credit A, as approved in MPSC Case No. U-, will expire when the Company implements new rates as a result of the instant case. Base rates approved in the instant case will include the effects of the TCJA, and therefore Credit A will no longer be necessary. While Staff proposes a revenue sufficiency of $7.6M, when coupled with the elimination of the TCJA Credit A amount of $.4M, the net result is a rate increase of $85.8M, as shown on Staff Exhibit S-, Schedule A-, lines 8, 9, and respectively. This effect is incorporated into Staff s proposed rates. The expiration of TCJA Credit A is not an adjustment to Staff s or the Company s case, but included to show that while Staff recommends a revenue sufficiency it would still result in a net rate increase for customers. Q. Please describe Staff Exhibit S-6, Schedule F- and Schedule F-.. A. Exhibit S-6, Schedule F- shows present and proposed revenue by rate schedule, and the increase or decrease in revenue for each rate. This exhibit does not include any adjustment for TCJA Credit A. Exhibit S-6, Schedule F-. compares Staff s present revenue, not including TCJA Credit A, to the Company s filed present revenue. Residential Rate Design 5

77 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II Q. Does Staff agree with the Company s proposed residential rate design? A. In general, yes. Staff, however, recommends an update to the Company s proposed summer on-peak transition plan, the creation of a transitional residential rate for that plan, and proposes eliminating the universal peak reward (UPR) provision in favor of a voluntary critical peak price (CPP) provision. Q. Has the Company made any revisions to its plan to transition customers to the proposed summer on-peak rate since its initial filing? A. Yes. Through audit, and as shown in Staff Exhibit S-7, the Company is proposing an alteration of the timeline of the project, as well as the addition of a pilot phase. The audit response states: With a project of this scale, the Company is proposing to test system design and integration, online customer apps and tools, and customer acceptance through a targeted pilot beginning in June 9. As a targeted pilot, the Company will select participants based on criteria defined as part of its current customer segmentation research. Customers interested in the pilot, but not selected to participate, may enroll in the pilot in May 9. Once enrolled, however, a customer must remain in the pilot until it ends. The pilot will continue through December 9 to evaluate the persistence of changes in customer electric use behavior following the summer season. The effectiveness of the pilot will depend on the ability for interval shifting, system integration, and readiness of customer apps and tools. 6

78 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II Following a successful pilot, all remaining.6 million residential customers with AMI meters will be transferred to the new Summer TOU Rate on January,. On June,, all residential customers will begin receiving an on-peak charge for electric use between : p.m. and 7: p.m. during the summer season of June st through September th. (Exhibit S-7.) Q. Does Staff agree with the alterations described by the Company? A. Yes. Upon initial review, Staff found the transition plan as filed by the Company to be overly vague. The Company filed its application in the instant case in May 8, which was just after the order in the Company s previous case was issued in March 8. The March 8 order directed the Company to, in its next general rate case, eliminate the inverted block rate for residential customers and replace it with a summer on-peak rate. Staff posits that the transition plan was overly vague because the Company had little time to prepare such a plan for inclusion in its rate case. However, it was at the Company s discretion when to file the instant case, and Staff does not assign blame for a less than coherent transition plan on any party but the Company. It seems apparent from audit responses that the Company took the time since filing the instant case to make revisions to its transition plan. While Staff found the initial plan concerning, the revisions found in Exhibit S-7 are reasonable, and they will lead to a better result. Q. What does Staff recommend regarding customers who have not yet been transitioned to the new summer on-peak rate? 7

79 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II A. In both the Company s filed transition plan and the updated version provided to Staff through audit there will be some portion of the test year where standard service residential customers will not yet be on the new summer on-peak rate. If those customers were to remain on Rate RS at its currently approved rates, then their rates would not be reflective of the COSS eventually approved in the instant case. The Company s proposed Rate RS (which will eventually become the AMI opt-out rate) is also not appropriate for yet-to-be transitioned customers, because it is designed with billing determinants that assume ten thousand or so opt-out customers. As found in Exhibit S-6, Schedule F-, page Staff developed a transitional rate for residential customers that retains the same previously approved inverted block rate design that is updated with billing determinants for the current Rate RS, instead of just opt-out customers. Staff proposes that customers who, in the test year, have not been transitioned to the summer on-peak rate be charged this transitional rate. Opt-out customers should also be charged the transitional rate until either January, under the Company s filed transition plan, or June, under the Company s updated transition plan. After the applicable final transition date, opt-out customers should then be charged the Rate RS found on Exhibit S-6, Schedule F-, page. Tariffs should be updated to reflect these dates and rates. Demand Response Q. How do demand response rates and the Company s proposed summer on-peak rate differ? 8

80 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II A. The fundamental difference between a demand response rate and the Company s summer on-peak proposal is the intent of each rate. The intent of a demand response rate, such as Staff s proposed Critical Peak Pricing (CPP) provision or the Company s proposed Universal Peak Reward provision (UPR), is to alter a customer s typical energy consumption for the purpose of reducing costs faced by the utility, and therefore reducing revenue needed from customers. The most easily identifiable cost reduction manifests in lower peak capacity needs, but there is debate and further research being done on the effects of demand response in distribution cost reduction as well. Demand response accomplishes cost reduction by introducing a prompt to the customer that elicits a response which alters the customer s demand for energy. The prompt ranges in complexity from a phone call made by the utility that asks the customer to reduce usage on a summer day to the customer allowing the utility to install a device on the customer s air conditioner that limits its use automatically. In this instance, the prompt is a rate structure that encourages energy use outside of peak times by offering a financial disincentive for on-peak usage. A demand response rate structure that encourages off-peak use is not designed for specific rate cost recovery, but instead designed for the purpose of shifting the customer s load. The analyst designing a demand response rate is tasked with determining the prices at which customers will respond, not the prices which efficiently recover revenue. The opposite is true for the Company s proposed summer on-peak rate. The proposed summer on-peak rate is designed to recover revenue assigned to the class in the cost of service study in a manner consistent with the causation of the underlying costs. The 9

81 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II proposed summer on-peak rate is a product of current costs, whereas a demand response rate attempts to change those same costs over time. Standard rates are tasked with cost recovery, whereas demand response rates are tasked with cost reduction and should be designed as such. The Company s proposed summer on-peak rate charges a higher power supply capacity rate in the summer months during a designated daily peak period. The difference in price between the summer peak period and all other hours is based on the difference between the average locational marginal prices (LMP) of those periods. Average LMP prices are used as a proxy for cost differences. In other words, the varying rates represent actual variance in costs faced by the utility and caused by the customer. Q. Why is it important to make a distinction between demand response rates and the proposed summer on-peak rate? A. The distinction is important because the purpose of the rate should inform its design, and the results of that design should then be evaluated for reasonableness and efficacy, in that order. The evaluation step in rate design determines if the rate accomplishes its purpose, and whether the rate is efficient, stable, and understandable. The standard residential rate is evaluated on how well it recovers its allocated revenue requirement, and a demand response rate is evaluated on how well it encourages customer behavior and if it was cost effective (i.e. the total cost reduction resulting from the program is greater than the cost of the program.) Because the two types of rate have different purposes, and therefore different evaluation goals, they are designed differently.

82 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II Q. Please describe Staff s proposed CPP provision. A. Staff s proposed CPP provision is, first, a demand response rate. A critical peak price is one that is charged only on a limited number of days each summer season, and the price takes the place of the standard on-peak rate. For example, the customer on Staff s CPP provision would pay the same rate for on-peak energy usage of 9.57 cents per kwh as other customers, but if the Company called a critical event, then the rate charged to CPP customers would be 95 cents, or 6.75 times higher. For reference, the current residential dynamic pricing Rate RDP charges 95 cents per kwh for critical events, and 95 cents was used in the Cadmus report used by the Company to support its proposed peak time rewards provision. For the entirety of the summer period, June through September, the CPP customer would enjoy an the standard off-peak rate reduced by half, or 4.79 cents instead of cents per kwh. CPP customers would then pay the same winter rates as other residential summer on-peak customers. The CPP provision would be optional to all summer on-peak customers. Q. How does Staff s proposed CPP provision differ from the Company s UPR provision? A. Where Staff s CPP provision diverges from the proposed UPR and currently approved Rate RDP is in its simplicity. The CPP provision is a modification to the summer on-peak rate, rather than a completely separate rate with its own unique prices and billing periods. There would be no mid-peak rate, and the customers would see the same prices as other residential customers for most of the year. This simplicity continues to the design of the CPP rates themselves, because the off-

83 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II peak discount is simply half of the standard rate. Customers will better be able to contextualize the rate if presented as a 5% discount. As I will discuss later, specific prices are less important to customers than relative prices. Telling a customer their rate will be reduced by 4 cents means that, in order for the customer to understand their level of savings, they must first know what they are already being charged. But telling a customer that their rate will be cut in half means that customers will instantly get a sense of how their bill will change. In other words, customers react to bill changes rather than rate changes. This concept is recognized in the Commission s own news releases, where residential impacts of rate orders are conveyed in dollars per month changes rather than cents per kwh. Additionally, by basing the CPP provision on the standard summer on-peak rate design, in the future as customers become more familiar with how their bills are affected by the new rate design they will better understand how the CPP provision can provide them savings. The Company relied on a consultant s report for recommendations regarding the UPR provision done by The Cadmus Group titled Peak Time of Use Pricing Options Program Annual Evaluation Report. The recommendations in the report show that customers are concerned with bill impacts rather than specific prices. The report also found that Customers were more satisfied with the event component than the pricing component despite having little difficulty shifting energy use to the less expensive times. (Cadmus Report, p 7.) The results of the report find that customers requested more information on how a CPP or peak time rebate (PTR) differed from the standard rate, and that after the

84 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II first summer event season customers wanted to see bill comparisons between program participation and non-participation. (Cadmus Report, pp 4-5.) The wording of those conclusions is important. Customers were interested in the bill differences, rather than the price differences between participation and nonparticipation. Also, Staff s CPP provision would make it easier for the Company to convey the difference between it and the standard rate, because the CPP provision is explicitly based on that rate. The Cadmus report also concludes that Meeting customers billsavings expectations is key for achieving higher program satisfaction. Page 6. Staff s proposal offers a rate discount that results in a higher on-off peak price ratio than the Company s current offerings, and thus would provide customers with greater bill impacts. Essentially, Staff s proposed CPP provision accomplishes the goal of two types of demand response rate. First the critical event component lets the rate be dispatchable, or able to be used by the Company at its discretion in response to wholesale price changes. Second, by reducing the off-peak rate, it creates a larger price differential than what is be dictated by forecasted LMP, thus transforming the standard rate into a time-of-use rate. In Staff s proposed CPP rate design, the resulting summer on-peak price is about times greater than the off-peak price with discount. By contrast, the on-off peak differential for the Company s proposed Rate RPD is only.74, and its time of use prices are still partially based on LMP. Q. When does Staff recommend implementation of the proposed CPP provision?

85 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II A. Staff proposes to implement the CPP provision along the same timeline as the Company proposed for its UPR provision. Staff expects that the billing system upgrades to implement the CPP provision to be largely similar to those needed to implement the UPR. In fact, a CPP provision may be less costly to implement because there is no need for the demand response management system to calculate estimated bill savings for each customer in order to provide bill credits. Just like the Company s proposal for the UPR provision, customers would be allowed to also enroll in the Company s residential air conditioner cycling program and be eligible for an $8 monthly bill credit in the summer season, where the customer receives the higher total credit between the CCP s total monthly off-peak discount (net of any critical peak charges) and the A/C cycling credit. Q. Why is the proposed CPP provision pricing structure affected by both capacity and non-capacity rates? A. The proposed CPP discount for off-peak energy is one half of the total off-peak energy rate, which includes capacity and non-capacity costs. As discussed previously in my direct testimony, demand response rates, such as the proposed CPP provision, are first concerned with the desired effect of shifting load, and not necessarily with cost causation. Because the proposed CPP provision is designed to be simple for customers to react to and simple for the Company to calculate, the total on- or off-peak rate is used to determine the discount. If Staff does not expect residential customers to know the specific prices charged for energy, then 4

86 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II Staff certainly does not expect them to know the different rates for capacity and non-capacity. Q. Is Staff s proposed CPP provision revenue neutral? A. First, revenue shortfalls or surpluses resulting from Staff s proposed CPP provision would be included in the demand response reconciliation process approved in MPSC Case U-869 and would offset overall DR program costs. Looking strictly at the revenue changes associated with the critical event price and the off-peak rate discount, then the effect on residential revenue collection depends on the number of events called and the number of participants in the provision. Assuming a summer off-peak usage of 598 kwh per month per customer (i.e. residential air conditioning load profile) with no load shifting, then the breakeven necessary for revenue neutrality is 6 critical events per season. Using the same load profile and rates (Staff s rate design discount plus 95 cent critical price) but adding a 5% load shift to off-peak hours, the provision is revenue neutral at 7 critical events per season. One event day is added to the revenue neutral breakeven point for approximately every 7% increment of load shifting. Q. Please describe other, non-price related components of Staff s proposed CPP provision. A. Staff proposes that its CPP provision follow the same program specifications as the Company s proposed UPR provision, except replacing the peak reward with a critical price, discounting the summer off-peak rate, and making the provision voluntary. Staff recommends that, just as the Company proposes, the provision be 5

87 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II limited to 4 seasonal critical event days, require the Company to notify customers of critical events at least by :59PM before it takes place, and require the customer to have a transmitting meter. The tariff language for Staff s CPP provision will mirror that of the Company s UPR provision, but with the changes previously described in this answer. Q. Does Staff expect that changes will be necessary to its proposed CPP provision in the future? A. Yes. The design of the CPP provision may need to be revised once the results from the pilot phase of transitioning customers to the standard summer on-peak rate become available. Q. Why does Staff recommend a CPP provision instead of a UPR provision? A. Staff prefers a CPP because the Company s proposed UPR suffers from a freeridership problem, is opaque and imprecise in its calculation, is non-voluntary and thus violates PA 4 of 6, and is no more effective than a CPP provision. Q. Please explain the problem of free-ridership. A. Free-ridership is when a consumer gains benefits from a public good without paying the costs for that good. The public good is something that all consumers have access to, but may not necessarily pay for. If one were to, for example, visit a public park in a neighboring town, then that person would enjoy the benefit of the public park (good) without contributing to the local taxes used to pay for the park. The Company s proposal to include all residential customers in the UPR provision (or even defaulting customers into the provision with an option to leave) means that some customers could enjoy the benefit of the UPR bill credit without 6

88 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II paying the costs. In this instance the costs are the efforts made by customers to shift or reduce usage during critical events. Remember, demand response rates, such as the proposed UPR, involve two steps: introducing a prompt to the customer followed by a response by that customer. If the customer who has been automatically enrolled in the UPR provision is away from home on vacation during a critical peak event, then the customer s usage at home is reduced not in response to the prompt from the Company, but out of sheer happenstance. If, however, that same customer is home during a critical event and does nothing to alter their energy use (or even increases their use), then that customer may see no difference in their bill. In other words, the prompt could elicit no response from the customer and result in an increase, no change, or decrease in critical event usage, yet the proposed UPR will reward the customer for only one of those outcomes. The problem with free-ridership for the UPR is therefore two-fold: it includes all customers regardless of their efforts to shift load, and it rewards customers regardless of their efforts to shift load. Staff s proposed CPP provision avoids these problems because it is strictly voluntary, and it includes both a cost of inaction and a benefit of action (in both the off-peak discount and the avoided critical charge). Like the previous example, if the CPP customer is away from home on vacation during a critical event, then the customer will benefit by avoiding the critical charge, but they will also lose the benefit of the off-peak discount. The CPP customer would not be overcompensated by comparing awayfrom-home usage to a baseline, like the UPR customer would. Q. How is the Company s proposed UPR opaque and imprecise? 7

89 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II A. The proposed universal peak reward amount is a calculation of estimated load reduction during a critical event. In order to calculate this estimation, the Company must first determine a baseline load shape for each customer, then compare the customer s load during the critical event to that baseline. The specific process by which the Company determines the customer s baseline is not presented in its filing. Because the bill credit is estimated after the critical event the customer does not actually know from what baseline the company will calculate the credit. In other words, the customer will not have a sense of how much load to shift or what effect that shift has on their bill credit, because they will not know the starting point at which they are measured. The UPR provision is also imprecise when compared to Staff s proposed CPP provision, because its designed on two determinants that will vary in the test year, rather than one. The UPR will vary both by the estimated baseline and customers actual usage, while the CPP will only vary on customers actual usage. Actual usage can be forecasted for test year rate design, and it can also be determined at the end of each meter read. The baseline necessary for the UPR for each customer will also vary in the test year, but will not be determined with each meter read, but rather calculated according to the Company s methods. In order to get the best results from a demand response rate the customer should be able to comprehend how their actions translate into bill savings (Cadmus Report p 8), and Staff is unconvinced that the Company s proposed UPR will do so. Staff s proposed CPP provision does not require the customer to know their starting baseline on which their load reduction is measured. The customer 8

90 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II will not have to remember how much energy they used on the last warm weekday afternoon and consider if it is worthwhile to leave the air conditioner running. Rather, the customer will know that energy will cost six times the normal amount tomorrow afternoon, but only half as much tomorrow evening. Q. Why does the Company s proposed UPR violate PA 4 of 6? A. MCL 46.95()a states that the Commission shall: Promote load management in appropriate circumstances, including expansion of existing and establishment of new load management programs in which an electric provider may manage the operation of energy consuming devices and remotely shut down air conditioning or other energy intensive systems of participating customers, demand response programs that use time of day pricing and dynamic rate pricing, and similar programs, for utility customers that have advanced metering infrastructure. Electric provider participation and customer enrollment in such programs are voluntary. However, electric providers whose rates are regulated by the Commission and whose rates include the cost of advanced metering infrastructure shall offer commission-approved demand response programs. The programs may provide incentives for customer participation and shall include customer protection provisions as required by the commission. To participate in a program, a customer shall agree to remain in the program for at least year. (emphasis added.) The Company s UPR provision is not voluntary. While the customer may opt-out of receiving notification of critical event days, all customers will still receive a bill credit for energy use reduction during the event. In other words, the customer is still participating in the program, but just may not know about it. Staff s proposed CPP provision would be voluntary, and participating customers would, by default, receive notification of peak events before they occur in the same manner as described by the Company. In the alternative, Staff would be amenable to the Company notifying all residential customers of critical event days, with the 9

91 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II option to decline the notification, so long as customers on the standard summer on-peak rate are made aware that their rates will not change because of the event. Default notification of critical events may drive enrollment in the CPP provision. Q. Does the Company s proposed summer on-peak rate, filed at the direction of the Commission, violate the same provision of PA 4 of 6? A. No. As discussed previously, the intent and design of the summer on-peak rate is not to provoke a response by customers (i.e. promote load management ), but rather it appropriately follows how the utility incurs costs to serve the average residential customer. The Company s long-standing commercial and industrial rates are designed with on-peak energy or demand charges to accomplish the same matching between how costs are caused and how they are recovered. It was only recently, with the completion of the Company s AMI rollout, that residential customer rates could effectively follow the same matching principal. Q. How alike were the results of the Company s piloted CPP and UPR programs? A. Very. The Company s Cadmus Report shows that survey results for a CPP program and a UPR-like program (called peak time rebate or PTR in the report) to be similar in enrollment experience, satisfaction, and likelihood to recommend the program. (Cadmus Report p 5, Table.) Also, the demand savings for each program type were similar. (Cadmus Report, p 9, and p 4, Table 6.) General Service Rate Design Q. Does Staff take issue with the Company s proposed general service rate design? A. No, but Staff s proposed rates are calculated to reflect Staff s proposed revenue requirement and COSS adjustments.

92 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II Primary Rate Design Q. Does Staff take issue with the Company s proposed primary rate design? A. In general, no, however Staff proposes changes to the Rate GP-GPD crossing point adjustment, the allocation of capacity costs to Rate EIP, and the penalty for non-interruption for proposed Rate GPD-GI. Q. What does Staff recommend regarding the crossing point adjustment for rate schedules GP and GPD? A. Staff recommends maintaining a crossing point adjustment for rates GP and GPD for the purposes of the instant case, but recommends altering the adjustment so that the customer load factor crossing point increases from 45% to 5%. The purpose of the crossing point adjustment is to avoid customer migration between the rates, which would result in cost shifts in the cost of service study (COSS), and also require the Company to contact affected customers and move them to a new rate. In order to maintain the current crossing point of a load factor of 45% Staff s rate design model would require a shift of $M of revenue requirement from Rate GPD to GP. In other words, rates would need to be artificially higher for Rate GP customers simply so that customers do not switch rates to lower their bills. However, Staff proposes a crossing point adjustment of $M in revenue requirement from Rate GPD to Rate GP in the instant case. This adjustment would increase the load factor at which customers are better off on rate GPD to 5% and above. In subsequent rate cases, Staff will propose further reduction to the crossing point adjustment until it reaches an amount congruous with the effort and expense required of the Company to move customers between rates. Staff

93 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II recommends that in those future rate cases the Company should include in its filing updated load profiles and billing determinants that incorporate a higher crossing point load factor than the previous case. Q. Why should the crossing point adjustment be gradually reduced over time? A. Reallocation of revenue requirement outside of the cost of service study is inappropriate unless the rate elements of the rate design necessitate such a reallocation, or if allocation in the COSS proves administratively burdensome. For example, revenue requirement associated with interruptible rates is tabulated through rate design, not the COSS, and is therefore more appropriately reallocated in the rate design model. As discussed by Company witness Collins, the crossing point adjustment is meant to avoid the real costs and hassle of moving customers from one rate to another. Staff recognizes these costs, but disagrees they are greater than the $M interclass subsidy created by the crossing point adjustment. Eventually, however, a minimal crossing point adjustment may be necessary to avoid the time and expense related to altering the cost of service study. Q. How are capacity costs allocated for Rate EIP? A. The currently approved method of allocating capacity costs to Rate EIP is to adjust revenues such that the overall rate increase for Rate EIP customers mimics the overall rate increase for Rate GPD customers. Rate EIP is allocated no capacity costs in the COSS. According to Staff s rate design this necessitates increasing Rate EIP s revenue requirement by $8M, with an equal and opposite adjustment for Rates GP and GPD. Staff recommends that this method be used in the instant case only.

94 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II According to Company witness Collins, The load profile that was used for EIP customers in the COSS assumes reduced loads during the high-peak summer pricing periods associated with the high-peak and critical-peak components of the rate, and thus results in a negative allocation of capacity costs to these customers. (Collins Direct, p 8.) Staff s COSS does likewise, and without the aforementioned adjustment Rate EIP would have negative power supply capacity rates. This is not a failing of the rate design model, but of the COSS. Assuming that EIP customers have different capacity needs in the COSS by creating a unique load profile and then reallocating capacity costs in the rate design is antithetical to one another. The allocation of capacity costs to Rate EIP is inappropriate in the rate design model for the same reason the crossing point adjustment should be eventually reduced or eliminated: because the allocation of costs belongs in the COSS. Q. How should capacity costs be allocated for Rate EIP? The COSS should include load profiles that appropriately allocate capacity costs. Staff recommends that the Commission require the Company to develop a COSS that includes capacity costs for Rate EIP customers in its next general rate case, so that there is no need for further reallocation in the rate design model. Q. Does Staff oppose the Company s proposed Rate GPD GI interruptible provision? A. In general, no. However, the Company s proposed tariff language for the new provision includes a non-interruption penalty of $ per kw for the highest 5- minute kw during the interruption period. A charge for non-interruption is

95 DIRECT TESTIMONY OF DAVID W ISAKSON CASE NUMBER U-4 PART II common penalty for interruptible rates, and such a charge is already part of the Company s currently approved interruptible provision for Rate GPD. However, the current charge for non-interruption is $5 per kw. Similarly, DTE Electric Company s interruptible supply rider R- also charges $5 per kw for noninterruption. Staff recommends that the non-interruption charge for the Company s proposed Rate GPD GI provision be increased to $5 per kw. Other Rate Design Issues Q. Does Staff have any further adjustments to the Company s proposed rate design? A. Yes. When allocating interruptible capacity costs, as shown on Company Exhibit A-6, Schedule F., line, the Company accidently neglected to account for the residential A/C cycling credit. Staff confirmed the error through audit, and it is corrected in Staff s model (Exhibit S-6, Schedule F-., line ). Q. Does Staff have any more recommendations regarding rate design or tariff changes? A. No. Staff takes no issue with, but does not necessarily support, other rate design and tariff changes not addressed by my or other Staff testimony. Q. Does this conclude your testimony? A. Yes. 4

96 S T A T E OF M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * In the matter of the application of ) CONSUMERS ENERGY COMPANY ) for authority to increase its rates for ) Case No. U-4 the generation and distribution of ) electricity and for other relief. ) ) EXHIBITS OF DAVID W. ISAKSON MICHIGAN PUBLIC SERVICE COMMISSION September, 8

97 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Summary of Present and Proposed Revenue by Rate Schedule Schedule: F- Total Revenues Page: of Witness: D. W. Isakson Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) Total Total Total Net Total Net Line Present Proposed Increase/ Increase/ No. Description Revenue Revenue (Decrease) (Decrease) $ $ $ % Bundled Service Residential Class Residential RS/Summer On Pk $,895, $,84,8 $ (7,78) (.7) Residential RT 8,66 8,76.4 Residential REV,49, Residential RDP,456, Residential RDPR 7,98 8, Residential Opt Out 8, 7,55 (75) (.9) 7 Total Residential Class,94,4,87,84 (7,57) (.6) Secondary Class 8 Secondary Energy-only GS 57,54 569,6 (,64) (.5) 9 Secondary Demand GSD 48,98 47,47 (9,5) (.) Secondary Energy-only GS TOU NA Total Secondary Class,55,9,4, (,6) (.) Primary Class Primary Energy-only GP 6,944 58,6 (5,78) (.5) Primary Demand GPD 87,86 98,77 46, Primary Energy Intensive Rate EIP,7,7, Primary Time of Use Pilot GPTU 6,6 6,88 (79) (.4) 6 Total Primary Class,,69,6,6 4,9.8 Lighting & Unmetered Class 7 Metered Lighting Service GML,8,79 (8) (4.5) 8 Unmetered Lighting Service GUL,47, Unmetered Exp. Lighting GU-XL 78.6 Unmetered Service GU 8,96 8,6 7.8 Total Lighting & Unmetered Class 4,546 4, Self-generation Class Small Self-generation GSG NA Large Self-generation GSG-,49,88 (,548) NA 4 Total Self-Generation Class,49,88 (,548) NA 5 Total Bundled Service $ 4,64,649 $ 4,,887 $ (4,76) (.) ROA Service Residential Class 6 Residential Service RS $ - $ - $ - NA 7 Residential Time-of-Day RT NA 8 Total Residential Class NA Secondary Class 9 Secondary Energy-only GS 95 9 () (.) Secondary Demand GSD 7,948 7,6 (785) (9.9) Total Secondary Class 8,9 8,96 (86) (9.) Primary Class Primary Energy-only GP, (67) (.4) Primary Demand GPD,486 8,9 (,554) (7.6) 4 Total Primary Class,7 9,99 (,8) (8.4) 5 Total ROA Service $,6 $ 8,5 $ (,67) (8.6) 6 Total Bundled and ROA Service $ 4,95,8 $ 4,5,89 $ (44,89) (.) Notes

98 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Summary of Present and Proposed Revenue by Rate Schedule Schedule: F- Power Supply Revenues Page: of Witness: D. W. Isakson Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) Total Total Total Net Total Net Line Present Proposed Increase/ Increase/ No. Description Revenue Revenue (Decrease) (Decrease) $ $ $ % Bundled Service Residential Class Residential RS/Summer On Pk $,8,78 $,67,75 $ (,977) (.) Residential RT 4,957 5, Residential REV Residential RDP 5,988 6, Residential RDPR 4,577 4, Residential Opt Out,57,68 (8) (.) 9 Total Residential Class,8,77,96,56 (,56) (.) Secondary Class Secondary Energy-only GS 6,769 6, Secondary Demand GSD 8,5 4,7 4,9. Secondary Energy-only GS TOU NA Total Secondary Class 7,78 75,95 5,4.7 Primary Class 4 Primary Energy-only GP 8,44 7,96 (45) (.) 5 Primary Demand GPD 77,898 87,87 44, Primary Energy Intensive Rate EIP,5,, Primary Time of Use Pilot GPTU 55,44 56, Total Primary Class 988,84,5,9 46, Lighting & Unmetered Class 8 Metered Lighting Service GML Unmetered Lighting Service GUL 5,85 6,5 8.7 Unmetered Exp. Lighting GU-XL () (7.) Unmetered Service GU 6,76 7,9 4.5 Total Lighting & Unmetered Class,9, Self-generation Class Small Self-generation GSG NA 4 Large Self-generation GSG-,548 - (,548) (.) 5 Total Self-Generation Class,548 - (,548) (.) 6 Total Bundled Service $,9,66 $,95,467 $ 8,86. ROA Service Residential Class 7 Residential Service RS $ - $ - $ - NA 8 Residential Time-of-Day RT NA 9 Total Residential Class NA Secondary Class Secondary Energy-only GS NA Secondary Demand GSD NA Total Secondary Class NA Primary Class Primary Energy-only GP NA 4 Primary Demand GPD NA 5 Total Primary Class NA 6 Total ROA Service $ - $ - $ - NA 7 Total Bundled and ROA Service $,9,66 $,95,467 $ 8,86. Notes

99 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Summary of Present and Proposed Revenue by Rate Schedule Schedule: F- Delivery Revenues Page: of Witness: D. W. Isakson Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) Total Total Total Net Total Net Line Present Proposed Increase/ Increase/ No. Description Revenue Revenue (Decrease) (Decrease) $ $ $ % Bundled Service Residential Class Residential RS/Summer On Pk $ 74,47 $ 657,7 $ (57,4) (8.) Residential RT,9,8 (9) (9.9) Residential REV Residential RDP 4,468 4,7 (97) (.) 7 Residential RDPR,4,6 (4) (.) 8 Residential Opt Out 6,7 6,6 (577) (8.6) 9 Total Residential Class 7, ,8 (58,47) (8.) Secondary Class Secondary Energy-only GS 9,486 5,996 (,49) (.7) Secondary Demand GSD 44,94, (,84) (9.5) Secondary Energy-only GS TOU NA Total Secondary Class 54,49 7,6 (7,4) (4.9) Primary Class 4 Primary Energy-only GP 5,5,75 (5,55) (.6) 5 Primary Demand GPD 98,98 6,78 (7,) (7.6) 6 Primary Energy Intensive Rate EIP (5) (87.8) 7 Primary Time of Use Pilot GPTU 7,7 6,794 (98) (.) 8 Total Primary Class,785 88,86 (4,94) (.) Lighting & Unmetered Class 9 Metered Lighting Service GML,5 96 (9) (8.8) Unmetered Lighting Service GUL 7,6 7,577 (5) (.) Unmetered Exp. Lighting GU-XL 5.6 Unmetered Service GU,56,574.9 Total Lighting & Unmetered Class,6, () (.) Self-generation Class 4 Small Self-generation GSG NA 5 Large Self-generation GSG-,88,88 () (.) 6 Total Self-Generation Class,88,88 () (.) 7 Total Bundled Service $,5,988 $,,9 $ (9,749) (9.6) ROA Service Residential Class 8 Residential Service RS $ - $ - $ - NA 9 Residential Time-of-Day RT NA Total Residential Class NA Secondary Class Secondary Energy-only GS 95 9 () (.) Secondary Demand GSD 7,948 7,6 (785) (9.9) Total Secondary Class 8,9 8,96 (86) (9.) Primary Class 4 Primary Energy-only GP, (67) (.4) 5 Primary Demand GPD,486 8,9 (,554) (7.6) 6 Total Primary Class,7 9,99 (,8) (8.4) 7 Total ROA Service $,6 $ 8,5 $ (,67) (8.6) 8 Total Bundled and ROA Service $,8,6 $,6,44 $ (,76) (9.5) Notes

100 Schedule F-. MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Calculation of Rate Design Targets Schedule: F-. ($) Page: of Witness: D. W. Isakson Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) ( h ) ( i ) ( j ) ( k ) ( l ) ( m ) ( n ) ( o ) ( p ) ( q ) ( r ) ( s ) Line Residential Class Secondary Class Primary Class Lighting & Unmetered Class Self Gen. Class No. Description Jurisdictional RS RT GS GS GEI GSD GSD GEI GP GP GEI GPD () GPD GEI EIP GML GUL GU-XL GU GSG- GSG- Cost-of-Service Study Power Supply () Capacity $ 99,964 $ 46,7 $ - $,8 $,47 $,77 $ 6,7 $ 5,8 $ 5,49 $ 4,754 $,546 $ 8, $ - $ - $ - $,85 $ - $ - COSS Capacity 99,964 4,45 -,77,9,889 6,6 7,95 5,45 7,58, ,8-7 Interruptible - 4,7.64 -, 55, (9,66.) EIP Capacity - (96.8) (.5) (6,689.9) (6.8) 8, Interclass Cross Pt Adj -, (,) 6 Self-Generation (7) 7 Energy,97,57 76,554-8,66 5,758 7,74,8 7,44,88 67,,47 4, ,44 5, COSS Energy,97,57 76,46-8,569 5,756 7,658,87 7,4,877 66,866,48 4, ,4 5, Self-Generation (797) Total Power Supply,96,,86,79-5,464 9,5,5 7,959,55 6,9 87,87,98, ,44 6, Delivery Distribution 979, ,65-66,89 6,6 8,4,74 4,94,464 7,65 5,9, ,95,55-69 Customer 8,68 9,9 -,8 7 4,6 98,859 5, Total Delivery,6,47 685,94-97, 6,885,46,47 6,76,697 78,45 6,7, ,49, Total Cost-of-Service $ 4,4,69 $,87,85 $ - $ 548,665 $ 5,99 $ 44,99 $,4 $ 7, $ 9,987 $ 949,8 $ 7,9 $ 4,8 $,77 $,5 $ $ 8,54 $ - $ 699 Skewing and Discounts () 5 Senior Citizen - (8,58) -,7, , Income Assistance - (,766) , Total Skewing and Discounts - (,4) -,845, , Total Rate Design Target $ 4,4,69 $,86,6 $ - $ 55,5 $ 5,99 $ 446,4 $,4 $ 8,5 $ 9,987 $ 954,88 $ 7,9 $ 4,4 $,77 $,5 $ $ 8,54 $ - $ 699 Notes () Capacity and energy costs adjusted to capture elements occurring outside the Cost-of-Service Study. () Skewing and Discount Allocation Factors. () Voltage Levels combined when entering from COSS. Jurisdictional RS RT GS GSD GP GPD EIP GML GUL GU-XL GU GSG- GSG

101 Schedule F-. MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Summary of Updated Present Revenue by Rate Schedule Schedule: F. Total Revenues Page: of Witness: D. W. Isakson Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) Staff Company Total Net Total Net Line Present Present Increase/ Increase/ No. Description Revenue Revenue (Decrease) (Decrease) $ $ $ % Bundled Service Residential Class Residential RS/Summer On Pk $,895, $,89,695 $ (,56) (.) Residential RT 8,66 8,49 (6) (.) Residential REV,49, Residential RDP,456, Residential RDPR 7,98 8,9.7 6 Residential Opt Out 8, 8,86 (4) (.) 7 Total Residential Class,94,4,98,4 (,99) (.) Secondary Class 8 Secondary Energy-only GS 57,54 57, (94) (.) 9 Secondary Demand GSD 48,98 48,55 (58) (.) Secondary Energy-only GS TOU NA Total Secondary Class,55,9,5,675 (,57) (.) Primary Class Primary Energy-only GP 6,944 6,86 (8) (.) Primary Demand GPD 87,86 87, Primary Energy Intensive Rate EIP,7,5 (85) (.4) 5 Primary Time of Use Pilot GPTU 6,6 6,4 () (.) 6 Total Primary Class,,69,,94 6. Lighting & Unmetered Class 7 Metered Lighting Service GML,8,755 (56) (.) 8 Unmetered Lighting Service GUL,47,5 () (.) 9 Unmetered Exp. Lighting GU-XL () (.) Unmetered Service GU 8,96 8,9 95. Total Lighting & Unmetered Class 4,546 4,48 (6) (.) Self-generation Class - Small Self-generation GSG NA Large Self-generation GSG-,49, NA 4 Total Self-Generation Class,49 -, NA 5 Total Bundled Service $ 4,64,649 $ 4,6,57 $ (4,9) (.) ROA Service Residential Class 6 Residential Service RS $ - $ - $ - NA 7 Residential Time-of-Day RT NA 8 Total Residential Class NA Secondary Class 9 Secondary Energy-only GS (4) (.4) Secondary Demand GSD 7,948 7,97 () (.) Total Secondary Class 8,9 8,877 (5) (.) Primary Class Primary Energy-only GP,45,4 () (.) Primary Demand GPD,486, Total Primary Class,7 -, Total ROA Service $,6 $,99 $ Total Bundled and ROA Service $ 4,95,8 $ 4,9,47 $ (,94) (.) Notes

102 Schedule F-. MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Summary of Updated Present Revenue by Rate Schedule Schedule: F. Power Supply Revenues Page: of Witness: D. W. Isakson Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) Staff Company Total Net Total Net Line Present Present Increase/ Increase/ No. Description Revenue Revenue (Decrease) (Decrease) $ $ $ % Bundled Service Residential Class Residential RS/Summer On Pk $,8,78 $,79,76 $ (966) (.) Residential RT 4,957 4,95 (4) (.) Residential REV Residential RDP 5,988 6, Residential RDPR 4,577 4, Residential Opt Out,57,497 (9) (.) 9 Total Residential Class,8,77,7,96 (79) (.) Secondary Class Secondary Energy-only GS 6,769 6,47 (98) (.) Secondary Demand GSD 8,5 7,87 (8) (.) Secondary Energy-only GS TOU NA Total Secondary Class 7,78 7,78 (55) (.) Primary Class 4 Primary Energy-only GP 8,44 8,9 (74) (.) 5 Primary Demand GPD 77,898 77,556 (4) (.) 6 Primary Energy Intensive Rate EIP,5,9 () (.) 5 Primary Time of Use Pilot GPTU 55,44 55,9 (47) (.) 7 Total Primary Class 988,84 987,597 (687) (.) Lighting & Unmetered Class 8 Metered Lighting Service GML () (.) 9 Unmetered Lighting Service GUL 5,85 6, 65.8 Unmetered Exp. Lighting GU-XL () (.) Unmetered Service GU 6,76 6, Total Lighting & Unmetered Class,9, Self-generation Class - Small Self-generation GSG NA 4 Large Self-generation GSG-,548, Total Self-Generation Class,548 -, Total Bundled Service $,9,66 $,9,94 $ (,78) (.) ROA Service Residential Class 7 Residential Service RS $ - $ - $ - NA 8 Residential Time-of-Day RT NA 9 Total Residential Class NA Secondary Class Secondary Energy-only GS NA Secondary Demand GSD NA Total Secondary Class NA Primary Class Primary Energy-only GP NA 4 Primary Demand GPD NA 5 Total Primary Class NA 6 Total ROA Service $ - $ - $ - NA 7 Total Bundled and ROA Service $,9,66 $,9,94 $ (,78) (.) Notes

103 Schedule F-. MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Summary of Updated Present Revenue by Rate Schedule Schedule: F. Delivery Revenues Page: of Witness: D. W. Isakson Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) Staff Company Total Net Total Net Line Present Present Increase/ Increase/ No. Description Revenue Revenue (Decrease) (Decrease) $ $ $ % Bundled Service Residential Class Residential RS/Summer On Pk $ 74,47 $ 7,9 $ (,54) (.4) Residential RT,9,96 () (.4) Residential REV Residential RDP 4,468 4, Residential RDPR,4, Residential Opt Out 6,7 6,689 (5) (.4) 9 Total Residential Class 7,697 7,494 (,) (.) Secondary Class Secondary Energy-only GS 9,486 8,849 (66) (.) Secondary Demand GSD 44,94 44,548 (76) (.) Secondary Energy-only GS TOU NA Total Secondary Class 54,49 5,97 (,) (.) Primary Class 4 Primary Energy-only GP 5,5 5,466 (64) (.) 5 Primary Demand GPD 98,98 99, Primary Energy Intensive Rate EIP Primary Time of Use Pilot GPTU 7,7 7, Total Primary Class,785, Lighting & Unmetered Class 9 Metered Lighting Service GML,5 997 (56) (5.) Unmetered Lighting Service GUL 7,6 7,5 (67) (.) Unmetered Exp. Lighting GU-XL () (.) Unmetered Service GU,56,557 (4) (.) Total Lighting & Unmetered Class,6 9,89 (7) (.) Self-generation Class - 4 Small Self-generation GSG NA 5 Large Self-generation GSG-,88, Total Self-Generation Class,88 -, Total Bundled Service $,5,988 $,49,45 $ (,57) (.) ROA Service Residential Class 8 Residential Service RS $ - $ - $ - NA 9 Residential Time-of-Day RT NA Total Residential Class NA Secondary Class Secondary Energy-only GS (4) (.4) Secondary Demand GSD 7,948 7,97 () (.) Total Secondary Class 8,9 8,877 (5) (.) Primary Class 4 Primary Energy-only GP,45,4 () (.) 5 Primary Demand GPD,486, Total Primary Class,7 -, Total ROA Service $,6 $,99 $ Total Bundled and ROA Service $,8,6 $,8,45 $ (,5) (.) Notes

104 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson Residential Service Summer On Peak Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity First 6 kwh/mth,84,898 MWh.6459 $ 74,599 $ - Excess kwh/mth,9,9 MWh.876 5,64 - On Peak 658,7 MWh ,64 4 Off Peak,57,76 MWh.66 6,679 Capacity 5 First 6 kwh/mth,84,898 MWh.44 94,59-6 Excess kwh/mth,9,9 MWh.446 6,5-7 On Peak 658,7.5749,97 8 Off Peak,57,76.467,4 9 Total Summer Power Supply 4,,89 445,875 4,444 Peak Saver 88, Bills (7.84) (,58) (8.) (,4) Peak Time Rewards Critical Peak Provision Critical Charge - MWh.44-4 On-Peak Capacity Discount - MWh Off-Peak Capcity Discount - MWh (.599) - Winter (Oct. - May) 6 Non Capacity All kwh/mth 7,69,8 MWh , , 7 Capacity All kwh/mth 7,69,8 MWh.44 54, ,77 8 TCJA Credit A- Capacity,9,69 MWh (.74) (,6) Annual PSCR Factor kwh/mth,9,69 MWh.8 9,58.8 9,58 Total Power Supply $,6,4 $,67,75 Delivery Distribution kwh/mth,9,69 MWh.55 $ 6,.45 $ 56,79 TCJA Credit A- Delivery,9,69 MWh (.) (5,768) System Access 8,778,6 Bills 7., ,86 5 Provisions 6 Senior Citizen RSC 4,8,4 Bills (.5) (4,44) (.75) (5,444) 7 Income Assistance RIA 68,6 Bills (7.) (4,77) (7.5) (5,) 8 Total Delivery $ 678,75 $ 657,7 9 ROA Service Delivery Distribution kwh/mth - MWh.55 $ -.45 $ - TCJA Credit A- Delivery - MWh (.) $ - - $ - System Access - Bills Provisions 5 Senior Citizen RSC - Bills (.5) - (.75) - 6 Income Assistance RIA - Bills (7.) - (7.5) - 7 Total Delivery $ - $ - 8 Total Residential RS $,89,6 $,84,8 Notes

105 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson Residential Service RS Transitional Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity First 6 kwh/mth,84,898 MWh.6459 $ 74, $ 7,448 Excess kwh/mth,9,9 MWh.876 5, ,6 Capacity First 6 kwh/mth,84,898 MWh.44 94, ,5 4 Excess kwh/mth,9,9 MWh.446 6, ,85 5 Total Summer Power Supply 4,,89 445,875 48,8 Winter (Oct. - May) Non Capacity 6 All kwh/mth 7,69,8 MWh , ,4 Capacity 7 All kwh/mth 7,69,8 MWh.44 54, ,595 8 TCJA Credit A- Capacity,9,69 MWh (.74) (,6) Annual PSCR Factor kwh/mth,9,69 MWh.8 9,58.8 9,58 Total Power Supply $,6,669 $,67,748 Delivery Distribution kwh/mth,9,69 MWh.55 $ 6,.45 $ 56,79 Skewing (.855) (.46) TCJA Credit A- Delivery,9,69 MWh (.) (5,768) System Access 8,778,6 Bills 7., ,86 Provisions 5 Senior Citizen RSC 4,8,4 Bills (.5) (4,44) (.75) (5,444) 6 Income Assistance RIA 68,6 Bills (7.) (4,77) (7.5) (5,) 7 Total Delivery $ 678,75 $ 657,7 ROA Service Delivery 8 Distribution kwh/mth - MWh.55 $ -.45 $ - 9 TCJA Credit A- Delivery - MWh (.) $ - - $ - System Access - Bills Provisions Senior Citizen RSC - Bills (.5) - (.75) - Income Assistance RIA - Bills (7.) - (7.5) - 4 Total Delivery $ - $ - 5 Total Residential RS $,84,74 $,84,8 Notes

106 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson Residential Service RS Smart Meter Opt Out Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity First 6 kwh/mth 6,5 MWh.6459 $,69.64 $,59 Excess kwh/mth,98 MWh.876, , Capacity First 6 kwh/mth 6,5 MWh Excess kwh/mth,98 MWh Total Summer Power Supply 9,49 4,6 4,9 Winter (Oct. - May) Non Capacity 6 All kwh/mth 76,667 MWh ,7.64 4,6 Capacity 7 All kwh/mth 76,667 MWh.44,54.65,58 8 TCJA Credit A- Capacity 6,58 MWh (.74) (98) Annual PSCR Factor kwh/mth 6,58 MWh Total Power Supply $,9 $,68 Delivery Distribution kwh/mth 6,58 MWh.55 $ 5, $ 5, Skewing (.855) (.9) TCJA Credit A- Delivery 6,58 MWh (.) (48) System Access,879 Bills Provisions 5 Senior Citizen RSC - Bills (.5) - (.75) - 6 Income Assistance RIA - Bills (7.) - (7.5) - 7 Total Delivery $ 6,65 $ 6,6 ROA Service Delivery 8 Distribution kwh/mth - MWh.55 $ -.45 $ - 9 TCJA Credit A- Delivery - MWh (.) $ - - $ - System Access - Bills Provisions Senior Citizen RSC - Bills (.5) - (.75) - Income Assistance RIA - Bills (7.) - (7.5) - 4 Total Delivery $ - $ - 5 Total Residential RS $ 7,674 $ 7,55 Notes

107 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 4 of Witness: D. W. Isakson Residential Dynamic Pricing RDP Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity Off-peak kwh/mth 5,9 MWh.477 $ $ 74 Mid-peak kwh/mth,578 MWh On-peak kwh/mth,588 MWh Critical-peak kwh/mth - MWh Capacity 5 Off-peak kwh/mth 5,9 MWh.779 $ 7.74 $ 45 6 Mid-peak kwh/mth,578 MWh On-peak kwh/mth,588 MWh Critical-peak kwh/mth - MWh Total Summer Power Supply,456,4,89 Winter (Oct. - May) Non Capacity Off-peak kwh/mth,57 MWh.574, On-peak kwh/mth,9 MWh.6587,4.6597,8 Capacity Off-peak kwh/mth,57 MWh On-peak kwh/mth,9 MWh Total Winter Power Supply,8,4 4 TCJA Credit A- Capacity 7,76 MWh (.74) () Annual PSCR Factor kwh/mth 7,76 MWh Total Power Supply $ 5,988 $ 6,7 Delivery 7 Distribution kwh/mth 7,76 MWh.55 $,57.45 $,8 8 TCJA Credit A- Delivery 7,76 MWh (.) $ () - $ - 9 System Access 58,44 Bills 7.,9 7.5,88 Provisions Senior Citizen RSC - Bills (.5) - (.75) - Income Assistance RIA - Bills (7.) - (7.5) - Total Delivery $ 4,468 $ 4,7 Total Residential RDP $,456 $,74 Notes

108 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 5 of Witness: D. W. Isakson Residential Dynamic Pricing Rewards RDPR Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity Off-peak kwh/mth,5 MWh.556 $ $ 596 Mid-peak kwh/mth 8,9 MWh On-peak kwh/mth,78 MWh Critical-peak kwh/mth - MWh (.69) - (.6887) - Capacity 5 Off-peak kwh/mth,5 MWh.75 $ $ 4 6 Mid-peak kwh/mth 8,9 MWh On-peak kwh/mth,78 MWh Critical-peak kwh/mth - MWh (.888) - (.49) - 9 Total Summer Power Supply,487,79,4 Winter (Oct. - May) Non Capacity Off-peak kwh/mth,99 MWh On-peak kwh/mth,798 MWh Capacity Off-peak kwh/mth,99 MWh On-peak kwh/mth,798 MWh Total Winter Power Supply,54,86 TCJA Credit A- Capacity 48,75 MWh (.74) (8) Annual PSCR Factor kwh/mth 48,75 MWh Total Power Supply $ 4,577 $ 4,75 Delivery 7 Distribution kwh/mth 48,75 MWh.55 $,48.45 $,7 TCJA Credit A- Delivery 48,75 MWh (.) $ (45) - $ - 8 System Access 58,44 Bills 7.,9 7.5,88 Provisions 9 Senior Citizen RSC - Bills (.5) - (.75) - Income Assistance RIA - Bills (7.) - (7.5) - Total Delivery $,4 $,6 Total Residential RDPR $ 7,98 $ 8,86 Notes

109 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 6 of Witness: D. W. Isakson Residential Electric Vehicle REV- (Home & Vehicle) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity On-peak kwh/mth 46 MWh.955 $ $ 45 Mid-peak kwh/mth,5 MWh Off-peak kwh/mth,7 MWh Capacity 4 On-peak kwh/mth 46 MWh.5 $ $ 5 5 Mid-peak kwh/mth,5 MWh Off-peak kwh/mth,7 MWh Total Summer Power Supply, Winter (Oct. - May) Non Capacity 8 On-peak kwh/mth, MWh Off-peak kwh/mth,56 MWh Capacity On-peak kwh/mth, MWh Off-peak kwh/mth,56 MWh Total Winter Power Supply 6, TCJA Credit A- Capacity 9,98 MWh (.544) (5) Annual PSCR Factor kwh/mth 9,98 MWh Total Power Supply $ 94 $ 977 Delivery 6 Distribution kwh/mth 9,98 MWh.55 $ $ TCJA Credit A- Delivery 9,98 MWh (.) $ () - $ - 8 System Access 9,78 Bills Total Delivery $ 54 $ 5 Total Residential REV- $,48 $,5 Notes

110 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 7 of Witness: D. W. Isakson Residential Electric Vehicle REV- (Vehicle Only Time-of-Day) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity On-peak kwh/mth - MWh.955 $ $ - Mid-peak kwh/mth MWh Off-peak kwh/mth 5 MWh Capacity 4 On-peak kwh/mth - MWh.5 $ $ - 5 Mid-peak kwh/mth MWh Off-peak kwh/mth 5 MWh Total Summer Power Supply 8 Winter (Oct. - May) Non Capacity 8 On-peak kwh/mth 4 MWh Off-peak kwh/mth MWh Capacity On-peak kwh/mth 4 MWh Off-peak kwh/mth MWh Total Winter Power Supply TCJA Credit A- Capacity 66 MWh (.544) () Annual PSCR Factor kwh/mth 66 MWh Total Power Supply $ 6 $ 6 Delivery 6 Distribution kwh/mth 66 MWh.55 $.45 $ 7 TCJA Credit A- Delivery 66 MWh (.) $ () - $ - 8 Total Residential REV- $ 9 $ 9 Notes

111 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 8 of Witness: D. W. Isakson Residential Time-of-Day RT Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity On-peak kwh/mth,69 MWh.8976 $ $ 86 Off-peak kwh/mth,64 MWh Capacity On-peak kwh/mth,69 MWh $ 6 4 Off-peak kwh/mth,64 MWh Total Summer Power Supply 7,56,466,557 Winter (Oct. - May) Non Capacity 6 On-peak kwh/mth 8,9 MWh Off-peak kwh/mth,45 MWh.584,88.567,84 Capacity 8 On-peak kwh/mth 8,9 MWh Off-peak kwh/mth,45 MWh , Total Winter Power Supply 4,48,444,77 Annual PSCR Factor kwh/mth 58,44 MWh TCJA Credit A- Capacity 58,44 MWh (.88) (8) - - Total Power Supply $ 4,876 $ 5,76 Delivery 4 Distribution kwh/mth 58,44 MWh.55 $,95.45 $,6 5 TCJA Credit A- Delivery 58,44 MWh (.) $ (75) - $ - 6 System Access 6,95 Bills Provisions 7 Senior Citizen RSC 7,4 Bills (.5) (5) (.75) (7) 8 Income Assistance RIA 66 Bills (7.) (4) (7.5) (5) 9 Total Delivery $,94 $,8 ROA Service Delivery Distribution kwh/mth - MWh.55 $ -.45 $ - TCJA Credit A- Delivery - MWh (.) $ - - $ - System Access - Bills Provisions Senior Citizen RSC - Bills (.5) - (.75) - 4 Income Assistance RIA - Bills (7.) - (7.5) - 5 Total Delivery $ - $ - 6 Total Residential RT $ 7,89 $ 8,76 Notes

112 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 9 of Witness: D. W. Isakson Residential Service Smart Hours Rate Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Proposed Smart Hours Non Capacity On Peak MWh Off Peak MWh Capacity On Peak Off Peak Total Summer Power Supply Peak Saver Bills (7.84) (8.) - 7 Peak Time Rewards - - Winter (Oct. - May) Non Capacity 8 On Peak Off Peak Capacity On Peak.7 - Off Peak Total Winter Power Supply - - Annual PSCR Factor kwh/mth MWh Total Power Supply $ - $ - Delivery 5 Distribution kwh/mth MWh.597 $ -.45 $ - 6 System Access Bills Provisions 7 Senior Citizen RSC Bills (.5) - (.75) - 8 Income Assistance RIA Bills (7.) - (7.5) - 9 Total Delivery $ - $ - ROA Service Delivery Distribution kwh/mth - MWh.597 $ -.45 $ - System Access - Bills Provisions Senior Citizen RSC - Bills (.5) - (.75) - 4 Income Assistance RIA - Bills (7.) - (7.5) - 5 Total Delivery $ - $ - 6 Total Residential Smart Savers $ - $ - Notes

113 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson Residential Service Nighttime Savers Rate Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Proposed Nighttime Savers Non Capacity On-peak kwh/mth Off-peak kwh/mth.77 - Super-peak kwh/mth Capacity 4 On-peak kwh/mth.56-5 Off-peak kwh/mth.48-6 Super-peak kwh/mth Total Summer Power Supply - - Winter (Oct. - May) Non Capacity 8 On-peak kwh/mth Off-peak kwh/mth Super-peak kwh/mth Capacity On-peak kwh/mth Off-peak kwh/mth Super-peak kwh/mth Total Winter Power Supply Annual PSCR Factor kwh/mth MWh Total Power Supply $ - $ - Delivery 7 Distribution kwh/mth MWh.597 $ -.45 $ - 8 System Access Bills Provisions 9 Senior Citizen RSC Bills (.5) - (.75) - Income Assistance RIA Bills (7.) - (7.5) - Total Delivery $ - $ - ROA Service Delivery Distribution kwh/mth MWh.597 $ -.45 $ - System Access Bills Provisions 5 Senior Citizen RSC Bills (.5) - (.75) - 6 Income Assistance RIA Bills (7.) - (7.5) - 7 Total Delivery $ - $ - 8 Total Residential Nighttime Savers $ - $ - Notes

114 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson Secondary Energy-only GS Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity All kwh/mth,94,787 MWh.6458 $ 89, $ 86,5 Capacity All kwh/mth,94,787 MWh.6 $ 45,7.6 $ 46,469 Provisions 4 Education GEI 5,95 MWh Total Summer Power Supply 5,6,8 Winter (Oct. - May) Non Capacity 6 All kwh/mth,46,86 MWh , ,67 7 Capacity 8 All kwh/mth,46,86 MWh.5 75, ,68 Provisions 9 Education GEI 6,67 MWh Total Winter Power Supply 4,595 7,748 Annual PSCR Factor kwh/mth,8,87 MWh.8,49.8,49 TCJA Credit A- Capacity,7,96 MWh (.654) (6,56) - - TCJA Credit A- Capacity GEI 88,967 MWh (.647) (47) Total Power Supply $ 56,466 $ 6,68 Delivery 5 Distribution kwh/mth,8,87 MWh.4765 $ 6, $ 59,485 6 Skewing TCJA Credit A- Delivery,7,96 MWh (.69) $ (,9) - $ - 8 TCJA Credit A- Delivery GE 88,967 MWh (.69) $ (9) - $ - 9 System Access,8,8 Bills. 46, ,577 Provisions Education GEI 88,967 MWh (.78) (6) (.74) (66) Total Delivery $ 99,7 $ 5,996 ROA Service Delivery Distribution kwh/mth,9 MWh.4765 $ $ 97 TCJA Credit A- Delivery 6,76 MWh (.69) $ (8) - $ - 4 TCJA Credit A- Delivery GE 5,6 MWh (.69) $ (4) - $ - 5 System Access, Bills Provisions 7 Education GEI 5,6 MWh (.78) () (.74) () Notes 8 Total Delivery $ 894 $ 9 9 Total Secondary GS $ 556,588 $ 57,546

115 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson Secondary Time of Use GSTU Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity Off-peak kwh/mth - MWh.5959 $ $ - Mid-peak kwh/mth - MWh On-peak kwh/mth - MWh Capacity 4 Off-peak kwh/mth - MWh.9848 $ -.97 $ - 5 Mid-peak kwh/mth - MWh On-peak kwh/mth - MWh Provisions 7 Education GEI - MWh Total Summer Power Supply Winter (Oct. - May) Non Capacity 9 Off-peak kwh/mth - MWh On-peak kwh/mth - MWh Capacity Off-peak kwh/mth - MWh On-peak kwh/mth - MWh Provisions Education GEI - MWh Total Winter Power Supply TCJA Credit A- Capacity - MWh () Annual PSCR Factor kwh/mth - MWh Total Power Supply $ - $ - Delivery 8 Distribution kwh/mth - MWh.4765 $ $ - 9 TCJA Credit A- Delivery - MWh (.69) $ - - $ - Skewing System Access - Bills Provisions Education GEI - MWh (.78) - (.74) - 4 Total Delivery $ - $ - 5 Total GSTU $ - $ - Notes

116 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson Secondary Demand GSD Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity Peak kw/mth,59 MW $ - 8. $ 8,974 All kwh/mth,86,5 MWh , ,79 Capacity Peak kw/mth,59 MW. $ 4,49. $ 47,8 4 All kwh/mth,86,5 MWh - - Provisions 5 Education GEI 54,75 MWh Total Summer Power Supply 8,669,7 Winter (Oct. - May) Non Capacity 7 Peak kw/mth 6,47 MW ,974 8 All kwh/mth,9,76 MWh.64 4,8.4 94,49 Capacity 9 Peak kw/mth 6,47 MW. 66,. 7,867 All kwh/mth,9,76 MWh - - Provisions Education GEI,84 MWh Total Winter Power Supply 6,48 6,89 TCJA Credit A- Capacity 9,77 MW (.6) (5,659) - - TCJA Credit A- Capacity GEI 689 MW (.6) (4) Annual PSCR Factor kwh/mth,578,957 MWh.8,86.8,86 5 Annual Power Factor Adjustment Total Power Supply $,95 $ 4,7 Delivery 7 Peak kw/mth 9,966 MW.5 $,46.5 $,46 8 Distribution kwh/mth,578,957 MWh.59 6,47.6,6 9 Skewing.69.6 TCJA Credit A- Delivery,9,6 MWh (.9) $ (8,) - $ - System Access 46,49 Bills. 7,95. 7,95 Provisions Education GEI 87,595 MWh (.69) (6) (.6) (9) TCJA Credit A- Delivery 87,595 MWh (.89) (448) - - Annual Power Factor Adjustment Total Delivery $ 6,64 $, ROA Service Delivery 5 Peak kw/mth 559 MW.5 $ 64.5 $ 64 6 Distribution kwh/mth,94 MWh.59 7,6.6 6,75 7 TCJA Credit A- Delivery 4,9 MWh (.9) (6) System Access 6,56 Bills Provisions 9 Education GEI 6,955 MWh (.69) $ (9) (.6) (4) TCJA Credit A- Delivery 6,955 MWh (.89) $ (5) - - Total Delivery $ 7,46 $ 7,6 Total Secondary GSD $ 475,76 $ 48,58 $ 47,898 Notes

117 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 4 of Witness: D. W. Isakson Primary Energy-only GP (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity All kwh/mth,64 MWh.5574 $ $ 7 Capacity All kwh/mth,64 MWh.47 $ $ 79 Provisions 4 Education GEI - MWh Total Summer Power Supply 5 6 Winter (Oct. - May) Non Capacity 6 All kwh/mth,65 MWh Capacity 8 All kwh/mth,65 MWh Provisions 9 Education GEI - MWh Total Winter Power Supply 5 TCJA Credit A- Capacity 4,9 MWh (.94) (4) - - TCJA Credit A- Capacity GEI - MWh (.94) Annual PSCR Factor kwh/mth 4,9 MWh Total Power Supply $ 56 $ 4 Delivery 5 Distribution kwh/mth 4,9 MWh.788 $.588 $ 5 8 Substation Ownership 49 MWh (.94) () (.9) () 9 System Access 6 Bills Provisions Education GEI - MWh (.5) - (.59) - TCJA Credit A- Delivery - MWh (.4) Total Delivery $ 8 $ ROA Service Delivery Distribution kwh/mth - MWh.788 $ $ - 4 TCJA Credit A- Delivery - MWh (.4) $ - - $ - 5 Substation Ownership - MWh (.9) - (.9) - 6 System Access - Bills Provisions 7 Education GEI - MWh (.5) - (.59) - 8 TCJA Credit A- Delivery - MWh (.4) Total Delivery $ - $ - Total Primary GP (Voltage Level ) $ 94 $ 65 Notes $ 59,4

118 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 5 of Witness: D. W. Isakson Primary Energy-only GP (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity All kwh/mth 9,55 MWh.557 $, $,55 Capacity All kwh/mth 9,55 MWh.67 $,65.49 $,5 Provisions Education GEI - MWh Total Summer Power Supply,69,557 Winter (Oct. - May) Non Capacity 5 All kwh/mth 58,55 MWh.5487,994.59,9 Capacity 6 All kwh/mth 58,55 MWh.469,8.76,96 Provisions 7 Education GEI - MWh Total Winter Power Supply 5, 4,99 9 TCJA Credit A- Capacity 87,67 MWh (.99) (8) - - TCJA Credit A- Capacity GEI - MWh (.99) Annual PSCR Factor kwh/mth 87,67 MWh Total Power Supply $ 7,69 $ 7,68 Delivery Distribution kwh/mth 87,67 MWh.77 $ $ 68 4 TCJA Credit A- Delivery 87,67 MWh (.568) $ (5) - $ - 5 Substation Ownership 8,644 MWh (.94) () (.) () 6 System Access 65 Bills Provisions 7 Education GEI - MWh (.5) - (.59) - TCJA Credit A- Delivery GE - MWh (.568) Total Delivery $ 956 $ 745 ROA Service Delivery 9 Distribution kwh/mth,845 MWh.77 $.7785 $ TCJA Credit A- Delivery,845 MWh (.568) $ () - $ - Substation Ownership - MWh (.94) - (.) - System Access 8 Bills.. Provisions Education GEI - MWh (.5) - (.59) - TCJA Credit A- Delivery GE - MWh (.568) Total Delivery $ $ 5 5 Total Primary GP (Voltage Level ) $ 8,67 $ 8,88 Notes

119 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 6 of Witness: D. W. Isakson Primary Energy-only GP (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity All kwh/mth 445,566 MWh.5974 $ 6, $ 6,94 Capacity All kwh/mth 445,566 MWh.477 $ 8,6.446 $ 7,9 Provisions Education GEI 54,99 MWh Total Summer Power Supply 45, 44,7 Winter (Oct. - May) Non Capacity 5 All kwh/mth 86,56 MWh , ,4 Capacity 6 All kwh/mth 86,56 MWh.49 4, ,49 Provisions 7 Education GEI,6 MWh Total Winter Power Supply 84,6 84,85 9 TCJA Credit A- Capacity,4,46 MWh (.99) (,55) - - TCJA Credit A- Capacity GEI 85,56 MWh (.97) (7) - - Annual PSCR Factor kwh/mth,9, MWh.8,47.8,47 Total Power Supply $ 9,4 $,9 Delivery Distribution kwh/mth,9, MWh.748 $, $ 7,596 4 TCJA Credit A- Delivery,4,46 MWh (.969) $ (,89) - $ - 5 System Access,5 Bills.,., 6 Provisions 7 Education GEI 85,56 MWh (.5) (98) (.59) () 8 TCJA Credit A- Delivery 85,56 MWh (.975) (8) Total Delivery $,4 $ 9,499 ROA Service Delivery Distribution kwh/mth 67,745 MWh.748 $,68.44 $ 9 TCJA Credit A- Delivery 4,666 MWh (.969) $ (4) - $ - System Access 555 Bills Provisions Education GEI 4,79 MWh (.5) () (.59) () 4 TCJA Credit A- Delivery 4,79 MWh (.975) () Total Delivery $ 765 $ 95 6 Total Primary GP (Voltage Level ) $ 4,8 $ 5,46 Notes

120 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 7 of Witness: D. W. Isakson Primary Demand GPD (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) ( h ) Line Billing Determinants Present Proposed No. Description Quantity Quantity Units Rates Revenue Rates Revenue Present Proposed $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity On-peak kw/mth,74,64 MW 7.74 $,64 9. $,78 On-peak kwh/mth 84,74 6,74 MWh.467, ,5 Off-peak kwh/mth 947,4 88,7 MWh.7 8, , Capacity 4 On-peak kw/mth,74,64 MW.66 8, $ 8,7 5 On Peak Transmission,74,64 MW.84,5 7.9 $ 9,5 Provisions 6 Interruptible GI MW (7.) (6,95) (7.) (,47) 7 Interr GI Cap & Trans 85,98 MWh.75,748 8 Interr GI LMP 85,98 MWh.7,756 9 Education GEI 8,455 8,455 MWh Total Summer Power Supply 7,6 6,8 Winter (Oct. - May) Non Capacity On-peak kw/mth,476, MW , ,4 On-peak kwh/mth 54,5 5,69 MWh.68 9,659.7,869 Off-peak kwh/mth,766,74,66,6 MWh.74 57,.95, Capacity 4 On-peak kw/mth,476, MW 9.66,58.4 4,685 5 On Peak Transmission,476, MW.86 6, , Provisions 6 Interruptible GI MW (6.) (5,5) (6.) (,668) 7 Interr GI Cap & Trans 7,797 MWh ,9 8 Interr GI LMP 7,797 MWh. 5, 9 Education GEI 5,75 5,75 MWh TCJA Credit A- Capacity,495,54 MWh (.55) (4,76) - - TCJA Credit A- Capacity 44,7 MWh (.6) (6) - - Total Winter Power Supply,5 7,545 Annual PSCR Factor kwh/mth,59,54,8,9 MWh.8,8.8,67 4 Annual Power Factor Adjustment (55) (556) 5 Total Power Supply $ 6,86 $,49 Delivery 6 Maximum kw/mth 7,9 7,9 MW.96 $ 6,999. 7,6 7 Skewing TCJA Credit A- Delivery 7,9 7,9 MW (.) $ (46) - $ - 8 Substation Ownership 6 6 MW (.8) () (.46) (8) 9 Joint Substation Ownership,98,98 MW (.6) (88) (.) (,6) System Access Bills Provisions Education GEI 44,7 44,7 MWh (.96) () (.7) (4) Annual Power Factor Adjustment (6) (6) Total Delivery $ 5,79 $ 6,4 ROA Service Delivery Maximum kw/mth,7,7 MW.96 $,99. $,86 TCJA Credit A- Delivery (.) - 4 Substation Ownership MW (.8) (4) (.46) (6) 5 System Access Bills Provisions Education GEI,86,86 MWh (.96) () (.7) () 7 Total Delivery $,9 $,995 8 Notes 9 Total Primary GPD (Voltage Level ) $,797 $,457

121 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 8 of Witness: D. W. Isakson Primary Demand GPD (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Quantity Units Rates Revenue Rates Revenue Present Proposed $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity On-peak kw/mth,45,7 MW 7.74 $,87. $,764 On-peak kwh/mth,7 89,48 MWh.487 9, ,89 Off-peak kwh/mth 568,4 5,865 MWh.7 8,9.,77 Capacity 4 On-peak kw/mth,45,7 MW.66 $ 6,8 5.4 $ 9,7 5 On Peak Transmission,45,7 MW.84 $, $ 9,9 Provisions 6 Interruptible GI 6 68 MW (7.) (,5) (7.) (,76) 7 Interr GI Cap & Trans 44,978 MWh.4567,85 8 Interr GI LMP 44,978 MWh.7,45 9 Education GEI 9,5 9,5 MWh Total Summer Power Supply 55,57 6, Winter (Oct. - May) Non Capacity On-peak kw/mth,855,57 MW 7.74,98 9.,978 On-peak kwh/mth 99,68 78,99 MWh.88 5,.578 9,75 Off-peak kwh/mth,5,455,8,97 MWh.474 9, ,4 Capacity 4 On-peak kw/mth,855,57 MW.66, , 5 On Peak Transmission,855, , ,6 Provisions 6 Interruptible GI MW (6.) (,87) (6.) (,69) 7 Interr GI Cap & Trans 89,956 MWh.79,6 8 Interr GI LMP 89,956 MWh.,798 9 Education GEI 5,76 5,76 MWh TCJA Credit A- Capacity,65,59 MWh (.5) (,65) TCJA Credit A- Capacity GE 54,795 MWh (.6) (75) Total Winter Power Supply 6,7 9,4 Annual PSCR Factor kwh/mth,,4,85,89 MWh.8,856.8,748 Annual Power Factor Adjustment (68) (8) Total Power Supply $ 6,95 $ 8,89 Delivery 4 Maximum kw/mth 5,64 5,64 MW.85 $ 9,554.9 $ 9,97 TCJA Credit A- Delivery 5,64 5,64 MW (.7) $ (6) 5 Substation Ownership MW (.65) (4) (.96) (66) 6 System Access,58,58 Bills Provisions 7 Education GEI 54,795 54,795 MWh (.96) (6) (.7) (8) 8 Annual Power Factor Adjustment () () 9 Total Delivery $ 9,7 $ 9,55 ROA Service Delivery Maximum kw/mth,98,98 MW.85 $ 5,54.9 $ 5,78 TCJA Credit A- Delivery,98,98 MW (.7) $ (9) Substation Ownership MW (.65) (5) (.96) (5) System Access Bills Provisions Education GEI 75,46 75,46 MWh (.96) () (.7) (5) 4 Total Delivery $ 5,9 $ 5,8 5 Total Primary GPD (Voltage Level ) $ 77,4 $ 96,85

122 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 9 of Witness: D. W. Isakson Primary Demand GPD (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Quantity Units Rates Revenue Rates Revenue Present Proposed $/unit $ $/unit $ Bundled Service Power Supply Summer (June - Sept.) Non Capacity On-peak kw/mth,57,8 MW 7.74 $ 7,65. $ 7,6 On-peak kwh/mth 49,97 49,975 MWh.597 6, $ 8,4 Off-peak kwh/mth,9,66,87,58 MWh.87 49,4.757 $ 5,4 Capacity 4 On-peak kw/mth,57,8 MW.66 $ 45,6 6.4 $ 5,96 5 On Peak Transmission,57,8 MW.84 $ 6, $ 5,4 Provisions 6 Interruptible GI MW (7.) (4,5) (7.) $ (,6) 7 Interr GI Cap & Trans,999 MWh.55 $ 4 8 Interr GI LMP,999 MWh.7 $ 9 9 Education GEI 76,96 76,96 MWh Total Summer Power Supply 5,5 68,68 Winter (Oct. - May) Non Capacity On-peak kw/mth 6,67 6,4 MW ,9. $ 6,69 On-peak kwh/mth 95,476 9,57 MWh.448 9, $ 8,95 Off-peak kwh/mth,89,7,8,68 MWh , $ 69,86 Capacity On-peak kw/mth 6,67 6,4 MW.66 77,9 5.4 $ 9,89 4 On Peak Transmission 6,67 6,4 MW.84, $ 46,66 Provisions 5 Interruptible GI,66 58 MW (6.) (6,996) (6.) $ (,498) 6 Interr GI Cap & Trans 7,997 MWh.56 $ 4 7 Interr GI LMP 7,997 MWh. $ 49 8 Education GEI 76,45 76,45 MWh TCJA Credit A- Capacity 4,85,7 MWh (.6) (6,56) TCJA Credit A- Capacity GE 5,78 MWh (.67) (46) 9 Total Winter Power Supply 6,84 97,569 Annual PSCR Factor kwh/mth 5,78,75 5,66,754 MWh.8 4,6.8 $ 4,6 Annual Power Factor Adjustment () () Total Power Supply $ 47, $ 469,989 Delivery Maximum kw/mth,94,94 MW 4. $ 5,65.65 $ 44,8 TCJA Credit A- Delivery,94 MW (.) $ (,88) 4 System Access 8,67 8,67 Bills.,75.,75 5 Provisions 6 Education GEI 5,78 5,78 MWh (.96) (75) (.7) $ (8) 7 Annual Power Factor Adjustment () () 8 Total Delivery $ 5,466 $ 48,48 ROA Service Delivery 9 Maximum kw/mth,99,99 MW 4. $,57.65 $,95 TCJA Credit A- Delivery,99 MW (.) $ (688) System Access,95,95 Bills Provisions Education GEI 5,985 5,985 MWh (.96) (45) (.7) $ (5) Total Delivery $,69 $,656 Total Primary GPD (Voltage Level ) $ 48,97 $ 5,5 Notes

123 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson General Service Primary Time-of-Use - GPTU (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Power Supply Summer (June - Sept.) Non Capacity High-/On-peak kwh/mth 4 MWh $ $ 4 Mid-peak kwh/mth 54 MWh Low-peak kwh/mth MWh Off-peak kwh/mth MWh Capacity 5 High-/On-peak kwh/mth 4 MWh.59 $.884 $ 6 Mid-peak kwh/mth 54 MWh Low-peak kwh/mth MWh Off-peak kwh/mth MWh Provisions 9 Education GEI - MWh Total Summer Power Supply Winter (Oct. - May) Non Capacity High-/On-peak kwh/mth MWh Mid-peak kwh/mth MWh Off-peak kwh/mth 8 MWh Capacity 4 High-/On-peak kwh/mth MWh Mid-peak kwh/mth MWh Off-peak kwh/mth 8 MWh Provisions 7 Education GEI - MWh Total Winter Power Supply TCJA Credit A- Capacity,485 MWh (.4) () 9 Annual PSCR Factor kwh/mth,485 MWh.8.8 Annual Power Factor Adjustment () () Total Power Supply $ 96 $ Delivery Maximum kw/mth 4 MW.96 $. $ 4 TCJA Credit A- Delivery 4 MW (.) $ () Substation Ownership - MW (.8) - (.46) - 4 System Access Bills.. 5 Annual Power Factor Adjustment () () Provisions 6 Education GEI - MWh (.96) - (.7) - 7 Total Delivery $ 5 $ 6 Notes 8 Total Primary GPTU (Voltage Level ) $ $ 8

124 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson General Service Primary Time-of-Use - GPTU (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Power Supply Present Summer (June - Sept.) Non Capacity High-/On-peak kwh/mth,87 MWh $ $ 48 Mid-peak kwh/mth 5,84 MWh Low-peak kwh/mth,89 MWh Off-peak kwh/mth 7,5 MWh Capacity 5 High-/On-peak kwh/mth,87 MWh.459 $ $ 7 6 Mid-peak kwh/mth 5,84 MWh Low-peak kwh/mth,89 MWh Off-peak kwh/mth 7,5 MWh Provisions 9 Education GEI - MWh - - Total Summer Power Supply,956,6 Winter (Oct. - May) Non Capacity High-/On-peak kwh/mth 4, MWh.5884 $ $ 47 Mid-peak kwh/mth 5,84 MWh Off-peak kwh/mth,945 MWh.4954,57.499,568 Capacity 4 High-/On-peak kwh/mth 4, MWh.678 $ $ 85 5 Mid-peak kwh/mth 5,84 MWh Off-peak kwh/mth,945 MWh Provisions 7 Education GEI - MWh Total Winter Power Supply,77,885 TCJA Credit A- Capacity 78,587 MWh (.94) () 9 Annual PSCR Factor kwh/mth 78,587 MWh Annual Power Factor Adjustment (4) (4) Total Power Supply $ 5,669 $ 5,95 Delivery Maximum kw/mth 94 MW.85 $ 6.9 $ 7 TCJA Credit A- Delivery 94 MW (.7) $ (4) Substation Ownership 7 MW (.65) () (.96) (64) 4 System Access 9 Bills Provisions 5 Education GEI - MWh (.96) - (.7) - 6 Annual Power Factor Adjustment () () 7 Total Delivery $ 7 $ 47 8 Total Primary GPTU (Voltage Level ) $ 5,94 $ 6,97 Notes

125 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson General Service Primary Time-of-Use - GPTU (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Power Supply Present Summer (June - Sept.) Non Capacity High-/On-peak kwh/mth 7, MWh.975 $, $,59 Mid-peak kwh/mth 6,4 MWh.87, ,6 Low-peak kwh/mth 7,569 MWh.79 5, ,95 4 Off-peak kwh/mth,66 MWh , ,56 Capacity 5 High-/On-peak kwh/mth 7, MWh.9959 $ $ 96 6 Mid-peak kwh/mth 6,4 MWh.88,4.74,56 7 Low-peak kwh/mth 7,569 MWh.466, ,9 8 Off-peak kwh/mth,66 MWh.,469.97,69 Provisions 9 Education GEI - MWh $ - $ - Total Summer Power Supply,86,94 Winter (Oct. - May) Non Capacity High-/On-peak kwh/mth,8 MWh.6454 $,8.689 $,8 Mid-peak kwh/mth 44,9 MWh.6668,74.666,667 Off-peak kwh/mth 49,85 MWh.54854,74.549,54 Capacity 4 High-/On-peak kwh/mth,8 MWh.48 $ $ Mid-peak kwh/mth 44,9 MWh ,65 6 Off-peak kwh/mth 49,85 MWh , ,56 Provisions 7 Education GEI - MWh $ - - $ - 8 Total Winter Power Supply 5,7 5,578 TCJA Credit A- Capacity 584,6 MWh (.94) (84) 9 Annual PSCR Factor kwh/mth 584,6 MWh Annual Power Factor Adjustment Total Power Supply $ 48,749 $ 5,7 Delivery Maximum kw/mth,65 MW 4. $ 6,74.65 $ 5,854 TCJA Credit A- Delivery,65 MW (.) $ (69) System Access,4 Bills Provisions 4 Education GEI - MWh (.96) - (.7) - 5 Annual Power Factor Adjustment 6 Total Delivery $ 7,5 $ 6,5 7 Total Primary GPTU (Voltage Level ) $ 55,799 $ 56,566 Notes

126 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson Primary Energy Intensive Rate (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Power Supply Summer (June - Sept.) Non Capacity Critical-peak kwh/mth 54 MWh.8495 $ $ 5 High-peak kwh/mth 7,6 MWh Mid-peak kwh/mth 8,4 MWh Low-peak kwh/mth 4,8 MWh.456, ,95 5 Off-peak kwh/mth 5,58 MWh.8,64.96,7 Capacity 6 Critical-peak kwh/mth 54 MWh.49 $.488 $ 7 7 High-peak kwh/mth 7,6 MWh Mid-peak kwh/mth 8,4 MWh Low-peak kwh/mth 4,8 MWh Off-peak kwh/mth 5,58 MWh Total Summer Power Supply $ 6,5 $ 7,7 Winter (Oct. - May) Non Capacity Critical-peak kwh/mth 9 MWh.7856 $ $ 7 High-peak kwh/mth,457 MWh Mid-peak kwh/mth,459 MWh Off-peak kwh/mth 54,456 MWh. 4, ,9 Capacity 6 Critical-peak kwh/mth 9 MWh.94 $ $ 9 7 High-peak kwh/mth,457 MWh Mid-peak kwh/mth,459 MWh Off-peak kwh/mth 54,456 MWh.687,596.75,665 Total Winter Power Supply $ 9,56 $, TCJA Credit A- Capacity 9,458 MWh (.474) $ (8) Annual Power Factor Adjustment $ (6) $ (6) Annual PSCR Factor kwh/mth 9,458 MWh.8.8 Total Power Supply $ 6, $ 7,69 Delivery 4 Maximum kw/mth,7 MW.96 $,5. $,79 5 Skewing.7 TCJA Credit A- Delivery,7 MW -. () 6 Substation Ownership,546 MW (.8) (968) (.46) (,7) 7 System Access 6 Bills.. 8 Annual Power Factor Adjustment () () 9 Total Delivery $ 44 $ Total Primary EIP (Voltage Level ) $ 6,56 $ 7,9 Notes

127 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 4 of Witness: D. W. Isakson Primary Energy Intensive Rate (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Power Supply Summer (June - Sept.) Non Capacity Critical-peak kwh/mth 6 MWh $ $ 6 High-peak kwh/mth,9 MWh Mid-peak kwh/mth,9 MWh Low-peak kwh/mth 7,8 MWh Off-peak kwh/mth 6,48 MWh Capacity 6 Critical-peak kwh/mth 6 MWh.449 $.58 $ 7 High-peak kwh/mth,9 MWh Mid-peak kwh/mth,9 MWh Low-peak kwh/mth 7,8 MWh Off-peak kwh/mth 6,48 MWh Total Summer Power Supply $,66 $,878 Winter (Oct. - May) Non Capacity Critical-peak kwh/mth 8 MWh.856 $.9485 $ High-peak kwh/mth, MWh Mid-peak kwh/mth,7 MWh Off-peak kwh/mth 45, MWh.4,55.89,74 Capacity 6 Critical-peak kwh/mth 8 MWh.44 $.5776 $ 7 High-peak kwh/mth, MWh Mid-peak kwh/mth,7 MWh Off-peak kwh/mth 45, MWh ,6 Total Winter Power Supply,764, TCJA Credit A- Capacity 75,997 MWh (.457) (5) Annual Power Factor Adjustment (4) () Annual PSCR Factor kwh/mth 75,997 MWh.8 $ 6.8 $ 6 Total Power Supply $ 4,46 $ 5,7 Delivery 4 Maximum kw/mth 4 MW.85 $ $ 788 TCJA Credit A- Delivery 4 MW (.7) (9) 5 Substation Ownership,7 MW (.65) (76) (.96) (,5) 6 System Access 88 Bills Annual Power Factor Adjustment () 8 Total Delivery $ (7) $ (9) 9 Total Primary EIP (Voltage Level ) $ 4,99 $ 4,78 Notes

128 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 5 of Witness: D. W. Isakson Primary Energy Intensive Rate (Voltage Level ) Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Power Supply Summer (June - Sept.) Non Capacity Critical-peak kwh/mth MWh.995 $ $ High-peak kwh/mth 6 MWh Mid-peak kwh/mth MWh Low-peak kwh/mth,9 MWh Off-peak kwh/mth,768 MWh Capacity 6 Critical-peak kwh/mth MWh.9 $.58 $ 7 High-peak kwh/mth 6 MWh Mid-peak kwh/mth MWh Low-peak kwh/mth,9 MWh Off-peak kwh/mth,768 MWh Total Summer Power Supply $ 7 $ 67 Winter (Oct. - May) Non Capacity Critical-peak kwh/mth 4 MWh $.985 $ High-peak kwh/mth 8 MWh Mid-peak kwh/mth 7 MWh Off-peak kwh/mth 9,686 MWh Capacity 6 Critical-peak kwh/mth 4 MWh.4 $ $ 7 High-peak kwh/mth 8 MWh Mid-peak kwh/mth 7 MWh Off-peak kwh/mth 9,686 MWh Total Winter Power Supply $ 5 $ 56 TCJA Credit A- Capacity 5,68 MWh (.455) $ (7) Annual Power Factor Adjustment $ (4) $ (4) Annual PSCR Factor kwh/mth 5,68 MWh.8.8 Total Power Supply $ 84 $ 97 Delivery 4 Maximum kw/mth 98 MW 4. $ 4.65 $ 58 TCJA Credit A- Delivery 98 MW (.) $ () 5 System Access 76 Bills Annual Power Factor Adjustment () () 7 Total Delivery $ 4 $ 7 8 Total Primary EIP (Voltage Level ) $,7 $,9 Notes

129 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 6 of Witness: D. W. Isakson Large Self-generation GSG- Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue Power Supply Primary On Peak Capacity Voltage Level 6 MW $,46 Voltage Level 98 MW 9 Voltage Level MW $/unit $ $/unit $ Delivery Standby kw/mth 4 Voltage Level,475 MW.96 $,46. $,484 5 Voltage Level 45 MW $ 66 6 Voltage Level MW $ 4 TCJA Credit A- Delivery,475 MW (.) () TCJA Credit A- Delivery 45 MW (.7) (4) TCJA Credit A- Delivery MW (.) () Substation Ownership 7 Voltage Level (96) MW (.8) 6 (.46) $ 44 8 Voltage Level 95 MW (.65) (9) (.96) $ (84) 9 Transmission Interconnect 96 MW (.96) (9) (.98) $ (94) Standby Option System Access Bills Supplement Option () System Access - Bills Total Delivery $,84 $,88 Notes () For customers who generate a portion of their load requirements, but take the majority of their power from Consumers Energy.

130 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 7 of Witness: D. W. Isakson Metered Lighting Service GML Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Power Supply Secondary Service Non Capacity All kwh/mth 4,84 MWh.5 $ $ 79 Primary Service Non Capacity All kwh/mth 75 MWh Annual PSCR Factor kwh/mth 4,989 MWh Total Power Supply $ 758 $ 769 Delivery Secondary Service 5 Distribution kwh/mth 4,84 MWh.6587 $ $ 89 TCJA Credit A- Delivery 4,84 MWh (.57) $ (5) 6 System Access,6 Bills.. Primary Service 7 Distribution kwh/mth 75 MWh TCJA Credit A- Delivery 75 MWh (.648) () 8 System Access 48 Bills.. 9 Total Delivery $ 948 $ 96 Total Metered Lighting GML $,77 $,79 Notes

131 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 8 of Witness: D. W. Isakson Unmetered Lighting Service GUL Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) ( h ) ( i ) ( j ) ( l ) ( m ) Billing Determinants Present Rates Proposed Rates Line Customer Company Watts Incl Total MWh Non Cap Non Cap No. Description Fixtures Fixtures Units Ballast Annual Service Fixture Revenue Service Fixture Revenue $/unit $/unit $ $/unit $/unit $ Mercury Vapor 5 Lumens -,86 Lights $ $ 5 75 Lumens 6 9,45 Lights 9 8, ,.77 6.,4 Lumens 4 4,64 Lights 8, Lumens 88 9,56 Lights 458, Lumens - - Lights Lumens - Lights, Total Mercury Vapor,96 66,45 -,5,5 High-Pressure Sodium Lumens 7,48 Lights Lumens 84,49,4 Lights 7 58, , ,669 4 Lumens,44,547 Lights 7, , ,478 Lumens 6 5, Lights 47, Lumens 54 7,644 Lights 8 9, , ,4 45 Lumens 8 79,59 Lights 48, , ,84 4 Total HP Sodium,6,899,564-9,58 9,79 Incandescent Lumens - 54 Lights Lumens 8 - Lights Lumens 4,5 Lights Lumens - Lights Total Incandescent, Fluorescent - Lumens - 5 Lights Metal Halide Lumens Lights Lumens - 5,556 Lights Lumens,9 Lights Lumens Lights Total Metal Halide 54 9, TCJA Credit A- Delivery,65 (.8459) (,) 6 Annual PSCR Factor kwh/mth,65 MWh Total Unmetered Lighting GUL $,46 $,6 Notes Present U-8 Proposed Classification Customer Company Customer Company 8 Power Supply (%) Delivery (%)

132 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: 9 of Witness: D. W. Isakson Unmetered Experimental Lighting Service GU-XL Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Power Supply Non Capacity All kwh/mth 4 MWh $ $ Annual PSCR Factor kwh/mth 4 MWh.8.8 Total Power Supply $ $ Delivery Customer Owned Equipment 4 Distribution kwh/mth MWh.684 $.4878 $ Company Owned Equipment 5 Distribution kwh/mth 4 MWh Fixture Charge/mth 9 Light TCJA Credit A- Delivery 4 MWh (.8459) () 7 Total Delivery $ $ 8 Total Unmetered Service GU-XL $ $ Notes

133 Schedule F- MICHIGAN PUBLIC SERVICE COMMISSION Case No.: U-4 Consumers Energy Company Exhibit No.: S-6 Staff Present and Proposed Revenue Detail Schedule: F- ($) Page: of Witness: D. W. Isakson Unmetered Service GU Date: 9//8 ( a ) ( b ) ( c ) ( d ) ( e ) ( f ) ( g ) Line Billing Determinants Present Proposed No. Description Quantity Units Rates Revenue Rates Revenue $/unit $ $/unit $ Power Supply Non Capacity All kwh/mth 9,9 MWh.56 $ 5,.5658 $ 5,4 Capacity All kwh/mth 9,9 MWh.87 $, $,85 TCJA Credit A- Capacity 9,9 MWh (.4) $ (4) Annual PSCR Factor kwh/mth 9,9 MWh Total Power Supply $ 6,76 $ 7,9 Delivery 5 Distribution kwh/mth 9,9 MWh.746 $, $,56 6 System Access 5,59 Bills.. TCJA Credit A- Delivery 9,9 MWh (.6) (9) 7 Total Delivery $,467 $,574 8 Total Unmetered Service GU $ 8, $ 8,6 Notes

134 STAFF EXHIBIT S-7 Request #: 86 Page of MPSC AUDIT REQUEST CASE NO: U-4 DATE OF REQUEST: 8/4/8 NO. DWI- REQUESTED BY: David W. Isakson DATE OF RESPONSE: 8//8 RESPONDENT: Hubert W. Miller III Question:. Please provide any updates or revisions to the Company s transition plan for implementing its proposed summer on-peak rate. a. Please include updated or revised timelines for the implementation of the proposed summer on-peak rate. b. Please include updates or revisions to the costs associated with the implementation of the proposed summer on-peak rate. c. Please include any research or workpapers upon which the updates or revisions relied. Answer: a. With a project of this scale, the Company is proposing to test system design and integration, online customer apps and tools, and customer acceptance through a targeted pilot beginning in June 9. As a targeted pilot, the Company will select participants based on criteria defined as part of its current customer segmentation research. Customers interested in the pilot, but not selected to participate, may enroll in the pilot in May 9. Once enrolled, however, a customer must remain in the pilot until it ends. The pilot will continue through December 9 to evaluate the persistence of changes in customer electric use behavior following the summer season. The effectiveness of the pilot will depend on the ability for interval shifting, system integration, and readiness of customer apps and tools. Following a successful pilot, all remaining.6 million residential customers with AMI meters will be transferred to the new Summer TOU Rate on January,. On June,, all residential customers will begin receiving an on-peak charge for electric use between : p.m. and 7: p.m. during the summer season of June st through September th. b. The Company projects it will require $ million of O&M expense and $9.7 million of capital to design, implement, and support the new Summer TOU Rate. A breakdown of the project investments are shown in the table below.

135 Request #: 86 Page of c. Please see the attached documents used in updating the Company s transition plan. U-4 MPSC Staff Audit Rqst 86 Attachment.pdf The Potential Economic and Health Hardship Effects of Time-Of-Use Rates U-4 MPSC Staff Audit Rqst 86 Attachment.pdf Peak Time of Use Pricing Options Program Annual Evaluation Report, 7 Program Year U-4 MPSC Staff Audit Rqst 86 Attachment.xlsx MPSC Audit Response B U-4 MPSC Staff Audit Rqst 86 Attachment 4.pdf Residential Customer Enrollment in Time-based Rate and Enabling Technology Programs U-4 MPSC Staff Audit Rqst 86 Attachment 5.xlsx Summer TOU Rate Exploratory Survey (June 8 Residential Panel Survey)