REBUTTAL TESTIMONY OF MARIA T. DIAZ DIRECTOR, RATES …

PETITIONER’S EXHIBIT 38

IURC CAUSE NO. 45253 REBUTTAL TESTIMONY OF MARIA T. DIAZ

FILED DECEMBER 4, 2019

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REBUTTAL TESTIMONY OF MARIA T. DIAZ DIRECTOR, RATES AND REGULATORY PLANNING

ON BEHALF OF DUKE ENERGY INDIANA, LLC CAUSE NO. 45253

BEFORE THE INDIANA UTILITY REGULATORY COMMISSION

I. INTRODUCTION 1

Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 2

A. My name is Maria T. Diaz, and my business address is 1000 East Main Street, 3

Plainfield, Indiana 46168. 4

Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY? 5

A. I am employed by Duke Energy Indiana, LLC (“Duke Energy Indiana,” 6

“Applicant” or “Company”) as Director, Rates and Regulatory Planning. Duke 7

Energy Indiana is a wholly owned, indirect subsidiary of Duke Energy 8

Corporation. 9

Q. ARE YOU THE SAME MARIA T. DIAZ THAT PRESENTED DIRECT 10

TESTIMONY IN THIS PROCEEDING? 11

A. Yes, I am. I 12

Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY? 13

A. I am responding to the certain portions of the prefiled testimony of Office of the 14

Utility Consumer Counselor (“OUCC”) witness Glenn A. Watkins, Citizens 15

Action Coalition of Indiana, Inc.(“CAC”)/Indiana Community Action 16

Association/Environmental Working Group (together “Joint Intervenors”) witness 17

Jonathan F. Wallach, The Duke Industrial Group (“IG”) witness Nicholas 18

Phillips, Jr., Walmart Inc. (“Walmart”) witness Steve W. Chriss, and The Kroger 19

thorn

New Stamp




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Co. (“Kroger”) witness Justin Bieber. My testimony rebuts their prefiled 1

testimony concerning: (1) coincident peak (“CP”) allocation methodology (“4 CP 2

vs. 12 CP”); (2) production demand allocation methodology; (3) distribution 3

demand allocation methodology; (4) distribution of the proposed rate changes; 4

and (5) subsidy/excess adjustment and connection charge. I make corrections to 5

my revised direct testimony that were discovered in the process of preparing this 6

rebuttal testimony. I also explain the Company’s proposed revision to its 7

decoupling tariff. I file updated exhibits and workpapers for the jurisdictional and 8

cost of service studies, as a result of the revenue requirement changes proposed by 9

the Company witnesses in their rebuttal testimony. 10

II. 4 CP VS. 12 CP 11

Q. DO ALL INTERVENORS AGREE WITH THE USAGE OF A 4 CP FOR 12

THE ALLOCATION OF PRODUCTION AND TRANSMISSION 13

INVESTMENT? 14

A. Of the three witnesses who filed testimony on the topic, only IG witness Phillips 15

agrees with this methodology. OUCC witness Watkins and Joint Intervenors 16

witness Wallach propose that the Commission approve 12 CP as the allocation 17

methodology. 18

Q. IS IG WITNESS MR. PHILLIPS CORRECT THAT THE PEAKS THAT 19

COMPRISE THE 4 CP ALL OCCUR IN THE SUMMER? 20

A. No. He reviewed 2014 through 2018 calendar year data and agrees with use of a 21

4CP; however, he stated that the trend was a summer 4CP period based on his 22




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calendar year review of 5 years. As referenced in my direct testimony, Duke 1

Energy Indiana’s cut off for its load research studies was based on 12 months 2

ended June 2018 actual data, which resulted in including a non-summer month, 3

the month of January 2018 (and not July of 2018). Including January as one of 4

the peaks is not an outlier and is reasonable as January is one of the 4 highest 5

peaks in 7 of the calendar years spanning an approximate 15-year timeframe from 6

2003 through June 2018 per the FERC Form No. 1, page 401b. However, the 7

trend data per the FERC Form No. 1 page 401b as summarized on Petitioner’s 8

Exhibit 38-D (MTD), shows that Duke Energy Indiana has different peak periods 9

than at the time of the last retail rate case. 10

Q. WHY DOES MR. WATKINS ARGUE AGAINST THE 4CP ALLOCATION 11

METHODOLOGY? 12

A. He states that it does not reasonably reflect cost causation. 13

Q. DO YOU AGREE WITH MR. WATKINS’ CONCLUSION THAT THE 4 14

CP DOES NOT REASONABLY REFLECT COST CAUSATION? 15

A. No, I do not. 16

Q. PLEASE EXPLAIN WHY YOU DISAGREE WITH MR. WATKINS’ 17

CONCLUSION. 18

A. Mr. Watkins’ argument is that the 4 CP only considers peak demands and does 19

not consider the manner in which the Company’s generation assets are being used 20

throughout the year. He states that an allocation methodology that only considers 21




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a few hours of peak demand presents a significant bias against low-load factor 1

and weather sensitive customer classes like the residential class. 2

Another consideration in support of using 4CP is the timing of scheduled 3

planned outages. Duke Energy Indiana does not generally schedule planned 4

outages during peak months. If a scheduled planned outage is not conducted in 5

the peak months, it shows that these are critical periods for peak load and supports 6

a CP allocation method other than a 12 CP method. 7

Further, operating reserves as a percentage of the peak load are generally 8

higher in the non-peak months than peak months, which is further indicative of a 9

CP allocation method other than a 12 CP. 10

Q. HAVE YOU ALSO REVIEWED MR. JONATHAN F. WALLACH’S 11

PREFILED TESTIMONY ON BEHALF OF THE JOINT INTERVENORS 12

PERTAINING TO THE 4 CP VS. 12 CP METHODOLOGY? 13

A. Yes, I have. 14

Q. WHAT ARGUMENTS DOES MR. WALLACH PUT FORTH IN SUPPORT 15

OF 12 CP OVER 4 CP AND WHY DO YOU DISAGREE WITH HIS 16

CONCLUSION THAT 12 CP IS MORE REASONABLE? 17

A. Mr. Wallach states that the Company’s investments in capacity to meet reserve 18

requirements are driven by demand in every month, not just by the demands in 19

peak months. Mr. Wallach draws an analogy to MISO stating that MISO 20

determines its annual reserve requirements based on demand throughout the year 21

and therefore, use of a 12 CP is a more reasonable measure of each class’ 22




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contribution to the need for new reserve capacity than 4 CP. Although I agree 1

that MISO performs loss of load studies that consider each and every hour in their 2

analyses, I do not agree that the MISO approach should be the reasoning for how 3

the Company allocates production and related costs. Mr. Wallach’s analogy 4

would suggest using more than 12 points of measurement, resulting in a large 5

number of hours being included in the development of the demand allocator; said 6

methodology was not the one prescribed coming from the last retail rate case. 7

Q. PLEASE EXPLAIN WHY THE 4 CP METHOD REMAINS A 8

REASONABLE METHOD FOR COST ALLOCATION. 9

A. Since the Commission previously determined that the 12 CP demand allocation 10

was appropriate for Duke Energy Indiana, but also acknowledged that the 4 CP 11

demand allocation method should be performed in the next retail rate case per the 12

stipulation in the Duke merger settlement in Cause No. 42873, it boils down to 13

whether there have been substantive changes known to have occurred on the 14

system since that determination was made. Endorsing the 4 CP method does not 15

dramatically change the allocation of costs to customers as stated in my direct 16

testimony so it does not unreasonably disadvantage customers who made 17

investments in response to previous cost assignments. The Company is bound to 18

support the settlement agreement with the OUCC in Cause No. 42873 and has 19

filed a 4 CP case, in addition to the 12 CP case in rebuttal, as it did in its direct 20

testimony. The OUCC agreed to not oppose a 4 CP case at the time of the Duke 21




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merger settlement but nevertheless has filed testimony against its use in this retail 1

rate case. 2

Q. WHY DID THE COMPANY FILE BOTH 4 CP AND 12 CP COST OF 3

STUDY VERSIONS IN THIS PROCEEDING? 4

A. Because the selection of a 4 CP or 12 CP is at the Commission’s discretion and 5

because filing a 4 CP was a requirement of the Commission Order approving the 6

settlement agreement in Cause No. 42873, the Company filed both 4 CP and 12 7

CP cost of study versions to permit the Commission to review both. I would note 8

that the Company used a coincident peak methodology to allocate demand costs 9

based on the customer class’ load at the time of the system peak load. A company 10

with a relatively flat load profile throughout the year would typically allocate 11

demand costs on a 12 CP basis because a 12 CP methodology allocates demand 12

costs based on an assumption that capacity is built to meet the demand season to 13

season, month to month and not just the maximum load on the system at any one 14

given time or any one segment of the year. In contrast, a peaking utility would 15

allocate demand costs more typically on a multiple-month basis, which assumes 16

that the load profile has a pronounced peak during those peak usage months. 17

III. PRODUCTION DEMAND ALLOCATION 18

Q. HAVE YOU REVIEWED MR. WALLACH’S PREFILED TESTIMONY 19

PERTAINING TO ALLOCATION OF PRODUCTION COSTS? 20

A. Yes, I have. 21




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Q. PLEASE EXPLAIN WHY YOU DISAGREE WITH MR. WALLACH’S 1

CONCLUSION THAT ALLOCATION OF PRODUCTION PLANT 2

SHOULD INCLUDE AN ENERGY COMPONENT, INCLUDING 3

RECOMMENDING USE OF AN EQUIVALENT PEAKER METHOD 4

(“EPM”)? 5

A. If the cost allocation included the 70% energy/30% demand allocation proposed 6

by Mr. Wallach, it would shift the design of rates by increasing energy charges 7

more so than what is already being proposed as part of this proceeding. 8

Historically, this Commission has not accepted an electric cost of service 9

study that classifies a portion of production plant as energy related and has 10

consistently rejected the use of EPM and there is no reason to depart from this 11

practice. There have been no changes in the Duke Energy Indiana system that 12

would warrant a change in the Commission’s historical treatment of production 13

plant as demand related. 14

Customers use the system on a year-round basis but the application of cost 15

causation leads to the conclusion that fixed costs should be allocated on a demand 16

as opposed to an energy basis. The Company must provide adequate generating 17

capacity to meet the demands of customers when those customers make those 18

demands on the system. 19

Mr. Wallach’s proposed use of the EPM would result in higher load factor 20

customers being impacted negatively. Adoption of EPM would further discourage 21

efficient use of the system because high load factor customers promote the 22




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efficient utilization of the system, which benefits all customers. Allocating 1

production as a demand related cost sends a cost-based pricing signal that 2

discourages power usage at the time of the system peak demand. Duke Energy 3

Indiana is not a proponent of dramatically changing the allocation of costs to 4

customers, as the EPM would, particularly when it may disadvantage customers 5

that have made investments in response to previous cost assignments. 6

Lastly, utilizing a blend of demand and energy to allocate production 7

investment contradicts the argument that there are peaks on the Duke Energy 8

Indiana electric system; IG witness Phillips supports the Company’s position by 9

stating that any method of cost allocation that utilizes a form of average demand 10

or energy to allocate production and transmission plant is at odds with the 11

dominant system peaks on the Duke Energy Indiana electric system and should be 12

rejected. 13

IV. DISTRIBUTION DEMAND ALLOCATION 14

Q. HAVE YOU REVIEWED MR. WALLACH’S PREFILED TESTIMONY 15

PERTAINING TO THE ALLOCATION OF DISTRIBUTION COSTS? 16

A. Yes, I have. 17


RECOMMENDATION THAT DISTRIBUTION PLANT COSTS 19

(SPECIFICALLY, SECONDARY POLES, CONDUCTORS, AND 20

TRANSFORMERS ON THE DISTRIBUTION SYSTEM) SHOULD BE 21

ALLOCATED BASED ON DIVERSIFIED CLASS DEMAND INSTEAD 22




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OF NON-COINCIDENT PEAK (“NCP”) AND THAT COSTS OF 1

PRIMARY POLES AND CONDUCTORS SHOULD BE ALLOCATED ON 2

DIVERSIFIED CLASS DEMAND EXCLUSIVELY? 3

A. Duke Energy Indiana’s practice for allocation of secondary poles, conductors, and 4

line transformers, which uses NCP demand that is the average of the 12 individual 5

customer level peaks has been in place since 1994, when it was approved in 6

Cause No. 40003. This standard practice recognizes that as the distribution 7

equipment used to deliver power gets closer in proximity to the customer, the 8

equipment varies based on the size of the customer. As such, the individual 9

customer’s load is what gives rise to the amount of costs incurred and determines 10

the cost assignment. The next step in the progression closer to the distribution 11

substation are the primary poles and conductors. For that allocation, the 12

Company’s practice has been to use a weighting that is based on both diversified 13

class (“DC”) demands and NCP. In other words, the Company assigns costs for 14

the back-bone system that connects customers to the distribution substations 15

based on class diversified demands and the single-phase service is allocated to the 16

single-phase rate classes on the basis of their respective non-coincident demands. 17

Then, Duke Energy Indiana’s practice for the allocation of the substation is at the 18

DC demand level exclusively, as the substation is sized to aggregate the class 19

customer load. There have not been substantive changes in how customers 20

connect to the distribution system from prior retail cases which would warrant a 21

change in cost assignment in this proceeding. 22




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V. DISTRIBUTION OF PROPOSED RATE CHANGES 1

Q. HOW DO INTERVENORS PROPOSE TO ADDRESS THE 2

APPLICATION OF ANY PROPOSED RATE CHANGES IN THIS 3

PROCEEDING? 4

A. OUCC witness Watkins recommends that any overall reduction to the Company’s 5

overall revenue requirement be spread in an inverse proportion to the proposed 6

customer class increases and that any overall increase less than that requested by 7

the Company be spread across rate classes in proportion to the increases proposed 8

by the Company. Walmart witness Chriss states that any reduction in revenue 9

requirement from the Commission should be applied in a manner that further 10

moves the customer classes towards their respective costs of service. No other 11

witness offered testimony on the topic 12


RECOMMENDATION THAT IF THERE IS AN OVERALL REDUCTION 14

TO THE COMPANY’S OVERALL REVENUE REQUIREMENT, IT 15

SHOULD BE SPREAD ACROSS THE CUSTOMER CLASSES IN 16

INVERSE PROPORTION TO THE COMPANY’S PROPOSED 17

CUSTOMER CLASS INCREASES AND LIKEWISE, IF THERE IS A 18

REDUCTION IN THE AUTHORIZED OVERALL INCREASE, THE 19

INCREASE SHOULD BE SCALED TO THE INCREASE BASED ON THE 20

COMPANY’S PROPOSED CUSTOMER CLASS REVENUE 21

ALLOCATION. 22




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A. First, Mr. Watkins is introducing speculation that an overall rate reduction could 1

result, and then suggesting that the rate reductions be applied in such a manner to 2

tighten the range of the ending revenue requirement across the classes. In the 3

event that there would be an overall rate reduction, the Company would continue 4

to allocate the rate reduction using the same method as filed in my direct 5

testimony, which is to spread any hypothetical, overall decrease in the same 6

proportion as the allocated, original cost depreciated rate base. The method to 7

allocate rate changes in this proceeding based on allocated original cost 8

depreciated rate base is consistent with the method used in the Company’s last 9

retail rate case. In addition, the Company’s allocation of rate changes based on 10

original cost depreciated rate base is sound, as the expenses associated with the 11

rate increase are already incorporated into the calculation of the proposed revenue 12

requirement by class; it is the return on the rate base that remains to be spread by 13

class and thus, attributing the rate change in the same proportion as the assigned 14

original cost depreciated rate base for the return component is reasonable. 15

Further, there is no reason to deviate from the Company’s subsidy/excess concept, 16

which it has used in prior rate cases to address the overall rate changes across the 17

classes. 18

If there is a reduction in the authorized overall increase, the reduction 19

could occur in any of the components of the case and to be accurate, the reduction 20

would be mapped at the regulatory account level and would follow the cost of 21

service methods for functionalization, classification, and allocation to derive the 22




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updated net operating income at the class level. As the potential reduction would 1

be tied to specific assets and expenses, it would be less accurate to spread the 2

reduction in totality and systemically spread across all the classes based on the 3

original, as filed proposed revenue allocation as recommended by Mr. Watkins. 4

Q. PLEASE ADDRESS WALMART WITNESS CHRISS’ 5

RECOMMENDATION THAT ANY REVENUE REDUCTION SHOULD 6

BE APPLIED TO THE CLASSES IN A MANNER THAT MOVES THE 7

CUSTOMER CLASSES TOWARD THEIR RESPECTIVE COSTS OF 8

SERVICE. 9

A. While that is the end goal in any cost of service study, the amount of further 10

movement is predicated upon the amount of revenue reduction to be ordered and 11

the classes impacted by proposed changes which are not known at this time. 12

However, it is the Company’s goal to reflect the appropriate costs of service to the 13

classes, while utilizing the established practice of subsidy/excess to ensure rates 14

are reasonable and fair across all the classes. 15

VI. SUBSIDY/EXCESS AND CONNECTION CHARGE 16

Q. WHAT DO INTERVENORS PROPOSE REGARDING THE COMPANY’S 17

PROPOSAL TO ADDRESS THE SUBSIDY EXCESS? 18

A. OUCC witness Mr. Watkins argues that the residential subsidy as calculated by 19

the Company is overstated due to the understatement of the Company’s forecasted 20

revenues for the residential class. Joint Intervenors’ witness Mr. Wallach argues 21

that the Company’s proposal to reduce the current subsidy to the residential class 22




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should be rejected due to rate shock sensitivity. IG witness Phillips argues that 1

the Company’s as filed subsidy/excess proposal is not reasonable for Rate HLF 2

customers. Kroger witness Bieber makes a supporting argument that a larger 3

subsidy excess reduction is needed. No other witnesses filed testimony on this 4

topic. 5


CONCLUSION THAT THE RESIDENTIAL SUBSIDY AS CALCULATED 7

BY THE COMPANY IS OVERSTATED DUE TO THE 8

UNDERSTATEMENT OF THE COMPANY’S FORECASTED REVENUES 9

FOR THE RESIDENTIAL CLASS. 10

A. As explained by rebuttal witness Mr. Phillip Stillman, usage of the most recent 11

three-year period to determine average usage per residential customer is flawed 12

because 2018 was an outlier year. Therefore, extrapolating an average residential 13

usage that includes 2018 is not reasonable. Witness Stillman explains that due to 14

the 2017 Federal Tax Cuts and Jobs Act, income statistics were favorable for 15

2018 and contributed to strong energy usage for the residential class in 2018. It is 16

not the Company’s long-term view that usage for residential customers is 17

increasing, as illustrated by Witness Stillman, due to energy efficiency and the 18

lapsing of the initial effect of the 2017 Federal Tax Cuts and Jobs Act. As the 19

Company assembled the rate case by filing a forecasted test period as allowed by 20

Ind. Code § 8‐1‐2‐42.7 and by using the Company-approved load forecast at the 21

time, which was the Fall 2018 load forecast (not the Spring 2019 load forecast nor 22




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a subsequent load forecast), it is not relevant to introduce a limited 3-year 1

historical calculation within the Cost of Service Study, applicable to the 2

residential class exclusively, and draw a conclusion that states that the Company 3

has overstated the net operating income impact of the residential subsidy by $31 4

million. 5


CONCLUSION THAT THE PROPOSAL TO REDUCE THE CURRENT 7

SUBSIDY TO THE RESIDENTIAL CLASS SHOULD BE REJECTED 8

DUE TO RATE SHOCK SENSITIVITY. 9

A. As the Company is not proposing to change its allocation methodologies from the 10

prior retail rate case (other than complying with the stipulation that a 4 CP 11

allocation method be filed with this Commission for its consideration), it is also 12

not proposing to change the proposed subsidy/excess factor at this time from the 13

as filed amount of 5.1%. In its prior retail cases, the Company has used the 14

subsidy/excess tool to bring the classes towards parity over time in support of the 15

concept of gradualism. Although it is true that the Company has not been in for a 16

rate case for several years, the Company is not electing to propose a more drastic 17

subsidy/excess percentage to remedy this fact. Just the opposite, the Company is 18

sensitive to the residential proposed customers’ rate increase, and therefore, 19

elected to apply a modest 5.1% as the subsidy reduction in lieu of a larger subsidy 20

reduction that would have increased proposed residential rates more while 21

lowering the rate impacts to other classes. The subsidy/excess concept is just 22




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another tool the Company has to address rate increases across the classes 1

consistent with the Company’s strategic objectives. 2

Ultimately, the decision as to which subsidy/excess percentage to apply 3

was a result of the overall strategic decision described by Duke Energy Indiana 4

Witnesses Pinegar and Davey to keep residential customers at a proposed increase 5

of lower than 20% (exclusive of taxes separately shown on a customer’s bill) 6

while also considering the proposed rate of increase across the rest of the retail 7

classes. The other classes, such as the industrial and commercial customers, share 8

the same goal of avoiding rate shock as it impacts the profitability in their 9

businesses and ability to grow their loads. The needs of all our retail classes were 10

considered in assessing the percentage of retail subsidy to apply in order to yield a 11

fair increase among the retail classes. 12

Q. PLEASE EXPLAIN WHY YOU DISAGREE WITH MR. PHILLIPS’ 13

CONCLUSION THAT THE COMPANY’S AS FILED SUBSIDY/EXCESS 14

PROPOSAL IS NOT REASONABLE AND MR. BIEBER’S SUPPORTING 15

ARGUMENT THAT A LARGER SUBSIDY EXCESS REDUCTION IS 16

NEEDED. 17

A. Mr. Phillips states that the 5.1% subsidy reduction is not sufficient and presents 18

higher adjustments as necessary, such as a 50% reduction. He draws analogies to 19

the Company’s prior retail rate case, where the subsidy/excess was 33% and states 20

that by using lower subsidy percentages in this case it would take a hundred years 21

to resolve bringing costs in alignment with cost of service. I do not agree with his 22




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hundred-year stance as we do not know what the subsidy/excess amount will be in 1

the future. Mr. Phillips’ 50% subsidy reduction example in this case would yield 2

an approximate 25% revenue increase to the residential class, which is outside the 3

Company’s range of tolerance. Also, because a modest subsidy reduction 4

percentage was used in this proceeding, it does not automatically suggest that a 5

similar level of subsidy reduction percentage would occur in future rate cases as 6

each retail case stands on its own as far as the amount of increase and the drivers 7

of future proposed increases and cost allocation methodologies. 8

Mr. Phillips’ proposal suggests that the current allocation methodology in 9

the cost of service understates industrial rates of return because the Company does 10

not use a minimum system approach to classify a portion of distribution costs as 11

customer-related. An analyst applying this minimum system method attempts to 12

construct a bare-bones version of the electric system based on the number and 13

location of utility customers, and maintains that the cost of that minimum system 14

is customer-related rather than demand-related. 15

Mr. Phillips recommends performing a minimum system study in future 16

proceedings (not this proceeding). Such a study would result in allocating more 17

distribution costs as customer-related and allocate more distribution costs to the 18

residential class as the counts of residential customers exceeds the counts of 19

industrial and commercial customers. This may have the impact of increasing the 20

fixed connection charge. The Company is also attuned to not increasing the 21

customer charge without an increase in the customary costs included in that 22




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charge. The Company is also cognizant that retail customers do not want an 1

increased fixed customer charge. Therefore, the Company has stayed consistent 2

with its most recent retail rate case of including meters and customer accounts in 3

the fixed connection charge, and not expanding that charge to potentially include 4

every distribution component necessary to provide service such as substations, 5

wires, poles, etc. 6

Mr. Bieber states that the 5.1% subsidy excess level only makes negligible 7

movement towards aligning revenues allocation with cost allocation. I agree that 8

the movement is minor; but there is movement. This movement is guided by the 9

concept of gradualism and because the overall revenue requirement adjustments 10

proposed by the Company in its rebuttal are 1.5% less than the as filed case as 11

discussed by Witness Davey, usage of the 5.1% reduction in subsidy/excess 12

remains valid with the results of such proposed increases reflected in Petitioner’s 13

Exhibit 38-B (MTD), Schedule 2. 14

Q. MESSRS. WATKINS AND WALLACH PRESENT PROPOSED 15

CHANGES TO THE METHODOLOGY USED TO CALCULATE THE 16

FIXED CONNECTION CHARGE. HOW DO YOU RESPOND? 17

A. To be clear, the proposed fixed connection charge is cost-based and reflects fully 18

embedded costs that include direct costs, overheads and uncollectible account 19

costs, which represent the totality of costs to connect our customers to our system 20

as defined by the Company in this proceeding. Therefore, I disagree with Mr. 21

Wallach who removes uncollectible costs from the fixed connection charge 22




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calculation and also disagree with Mr. Watkins who further removes overheads 1

and other indirect costs. 2

VII. CORRECTIONS TO REVISED TESTIMONY AND 3 OTHER CHANGES IN THE JURISDICTIONAL STUDIES 4

Q. DO YOU HAVE CORRECTIONS TO YOUR REVISED DIRECT 5

TESTIMONY? 6

A. Yes. During the course of preparing this rebuttal testimony, it became apparent 7

there were three allocator assignment changes that needed to be made that 8

impacted depreciation expense in the jurisdictional study. There were two 9

depreciation expense allocator assignments that were 100% assigned to retail that 10

should have received a production-demand assignment and one allocator 11

assignment that received a production-demand assignment that should have 12

received a 100% assignment to wholesale. The net impact of these changes 13

reduced the retail rate increase by approximately $260,000 and is included in 14

Petitioner’s Confidential Exhibit 38-A (MTD) and Exhibit 38-B (MTD). The 15

changes are listed on Rebuttal MSFR Workpaper JS3 (MTD), lines 7 through 9 16

included in Petitioner’s Confidential Rebuttal Workpaper 1-MTD. 17

Q. DID YOU MAKE ANY OTHER CHANGES TO THE JURISDICTIONAL 18

STUDY? 19

A. No, I did not. Industrial Group witness Dauphinais proposes a full allocation of 20

costs associated with a 100 MW contract that is a short-term bundled non-native 21

contract. I continue to reflect the contract in accordance with the proposed 22

sharing of the contract in Rider No. 70, as was initially described by Witnesses 23




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Sieferman and Verderame in their direct testimony, and corroborated by Witness 1

Davey in his rebuttal testimony. I also did not impute an increased, hypothetical 2

level of wholesale sales as recommended by Witness Dauphinais in an attempt to 3

reduce the retail revenue requirement; this was also refuted by Witness Davey in 4

his rebuttal testimony. 5

VIII. DECOUPLING TARIFF 6

Q. IN RESPONSE TO OUCC WITNESS DISMUKES’ COMPLAINT THAT 7

THE COMPANY’S PROPOSED REVENUE DECOUPLING PROPOSAL 8

DOES NOT HAVE A CAP, IS DUKE ENERGY INDIANA PROPOSING 9

ANY CHANGES TO ITS PROPOSAL? 10

A. Yes. As discussed in Dr. Hansen’s rebuttal testimony, the Company is proposing 11

a cap on annual deferrals of 4%. 12

Q. DID YOU MAKE CHANGES TO THE DECOUPLING TARIFF TO 13

REFLECT THIS CHANGE? 14

A. Yes, I did. This change is included at the end of part 3 of Petitioner’s Exhibit 15

38-C (MTD). I inserted the following sentence in the proposed tariff, “The 16

annual RDM dollar adjustment for each rate class shall not exceed more than four 17

percent of allowed revenues for each rate class. Deferrals in excess of the four 18

percent are carried over to the subsequent year(s) RDM deferral balance 19

computation (or retail rate case).” Each year, the excess over the four percent 20

from the prior year(s) is included in the current year calculation for the annual 21




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RDM dollar adjustment, also subject to a four percent cap on allowed revenues 1

for the current year. 2

IX. CONCLUSION 3

Q. WERE PETITIONER’S CONFIDENTIAL EXHIBIT 38-A (MTD), 4

EXHIBIT 38-B (MTD), EXHIBIT 38-C (MTD), EXHIBIT 38-D (MTD), 5

CONFIDENTIAL REBUTTAL WORKPAPER 1-MTD AND 6

CONFIDENTIAL REBUTTAL WORKPAPER 2-MTD PREPARED BY 7

YOU OR UNDER YOUR SUPERVISION IN ACCORDANCE WITH THE 8

REBUTTAL POSITIONS AND OTHER CORRECTIONS PROPOSED BY 9

THE COMPANY? 10

A. Yes, they were. Petitioner’s Confidential Exhibit 38-A (MTD) Schedules 1 11

through 6 support the “Calculation of Net Operating Income for Wholesale and 12

Retail Customers” at the Jurisdictional Study and is an update to Petitioner’s 13

Confidential Exhibit 7-D (MTD) Schedules 1 through 6 filed in my direct 14

testimony. Petitioner’s Exhibit 38-B (MTD) Schedules 1 and 2 support the 15

“Summary of Net Operating Income and Rate of Return under Present and 16

Proposed Rates for Retail Customers by Rate Group” at the Retail Cost of Service 17

Study step (4CP) and is the updated version of Petitioner’s Confidential Exhibit 7-18

G (MTD) Schedules 1 and 2 (4CP). Petitioner’s Exhibit 38-C (MTD) is the 19

updated decoupling tariff. Petitioner’s Exhibit 38-D (MTD) is the Company’s 20

production peaks. Petitioners’ Confidential Rebuttal Workpaper 1-MTD includes 21

JS1-JS21 (MTD) and COSS1-COSS30 (MTD), and is the updated version of the 22




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Company’s Excel-based COSS replica,1 which support Petitioner’s Confidential 1

Exhibit 38-A (MTD) and Exhibit 38-B (MTD) for 4CP. A 12CP version of the 2

COSS replica was also filed as Petitioner’s Confidential Rebuttal Workpaper 3

2-MTD and includes JS22-JS42 (MTD) and COSS31-COSS60 (MTD). In my 4

revised direct Petitioner’s Exhibit 7-G (MTD) Schedule 2, the overall proposed 5

rate increase was 15.43% (not including Utility Receipts Tax) and in Petitioner’s 6

Exhibit 38-B (MTD) Schedule 2, the overall proposed rate increase is 13.96% 7

(not including Utility Receipts Tax). Witness Davey explains the Company’s 8

changes resulting in the lower overall proposed rate increase to retail customers. 9

Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY? 10

A. Yes, it does. 11

1 The COSS replica is a series of Excel-based schedules that were prepared and previously provided to the intervening parties and the Commission which verified the results of the Company’s PowerPlan model used for the preparation of the Jurisdictional Separation Study and Retail Cost of Service study.

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A B C D E F G H I J KPetitioner's Exhibit 38‐A (MTD)

IURC Cause No. 45253Schedule 1Page 1 of 1

Adjusted Updated Electric Total TotalTotal Pro Forma Revenue Total Total Steam Utility To Be Wholesale Retail

Description Company Adjustment Credits Company Adjustments Company Service Allocated Customers Customers

Rate Base 11,316,266$ (617,705)$ ‐$ 10,698,561$ 5,960$ 10,704,521$ $ $ $ 10,195,192$

Operating Revenues 2,926,978 (121,200) (84,188) 2,721,590 ‐ 2,721,590 2,517,952

Operation and Maintenance Expenses 1,680,533 (136,389) (84,188) 1,459,956 (2,000) 1,457,956 1,355,783

Depreciation and Amortization 563,526 185,156 ‐ 748,682 (12,960) 735,722 693,925

Taxes Other than Income Taxes 91,584 (19,657) ‐ 71,927 ‐ 71,927 68,569

Deferred Income TaxesFederal 36,812 (24,900) ‐ 11,912 2,588 14,500 16,228 State 21,237 (11,175) ‐ 10,062 (2,941) 7,121 7,127 Total Deferred Income Taxes 58,049 (36,075) ‐ 21,974 (353) 21,621 23,355

Investment Tax Credit (382) ‐ ‐ (382) ‐ (382) ‐ (350)

Current Income TaxesFederal 23,695 15,577 ‐ 39,272 2,896 42,168 30,741 State (4,882) 7,778 ‐ 2,896 3,090 5,986 3,570 Total Current Income Taxes 18,813 23,355 ‐ 42,168 5,986 48,154 34,311

Total Operating Expenses 2,412,123 16,390 (84,188) 2,344,325 (9,327) 2,334,998 2,175,593

Net Operating Income 514,855$ (137,590)$ ‐$ 377,265$ 9,327$ 386,592$ $ 342,359$

(Thousands of Dollars)

As Filed

DUKE ENERGY INDIANA, LLCCalculation of Net Operating Income for

The Company's Wholesale and Retail CustomersFor the Twelve Months Ended December 31, 2020

PETITIONER’S EXHIBIT 38-A (MTD) IURC Cause No. 45253

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A B C D E F G H I JPetitioner's Exhibit 38‐A (MTD)


TotalCompany Adjusted Updated Electric Total Total

Original Cost Pro Forma Original Cost Original Cost Steam Utility To Be Wholesale RetailDescription Depreciated Adjustment Depreciated Adjustments Depreciated Service Allocated Customers Customers

Electric Plant in ServiceProduction Plant 5,769,941$ (538,934)$ 5,231,007$ 1,982$ 5,232,989$ $ 4,791,650$ Transmission Plant 1,490,136 (34,033) 1,456,103 ‐ 1,456,103 1,453,178 Distribution Plant 2,581,405 (45,375) 2,536,030 ‐ 2,536,030 ‐ ‐ 2,536,030 Total Classified Plant 9,841,482 (618,342) 9,223,140 1,982 9,225,122 8,780,858

General Plant 427,852 1,412 429,264 ‐ 429,264 406,662 Intangible Plant 27,357 775 28,132 ‐ 28,132 26,651 Total Electric Plant in Service 10,296,691 (616,155) 9,680,536 1,982 9,682,518 9,214,171

Regulatory AssetsProduction Related 366,674 19,062 385,736 2,880 388,616 ‐ 387,548 Transmission Related 19,551 (4,035) 15,516 415 15,931 ‐ ‐ 15,931 Distribution Related 37,334 (6,270) 31,064 515 31,579 ‐ ‐ 31,579 General Related 1,555 (284) 1,271 168 1,439 ‐ ‐ 1,439 Total Regulatory Assets 425,114 8,473 433,587 3,978 437,565 ‐ 436,497

Pre‐Paid Pension Asset 150,740 ‐ 150,740 ‐ 150,740 142,803

Fuel and Emission Allowance Inventory 135,908 (9,813) 126,095 ‐ 126,095 114,796

Plant Materials and Supplies Inventory 307,813 (210) 307,603 ‐ 307,603 286,925

Total Original Cost Depreciated Rate Base 11,316,266$ (617,705)$ 10,698,561$ 5,960$ 10,704,521$ $ 10,195,192$

As Filed

DUKE ENERGY INDIANA, LLCAllocation of Original Cost Depreciated Rate Base toThe Company's Wholesale and Retail Customers

As of December 31, 2020(Thousands of Dollars)


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TotalCompany Adjusted Updated Electric Total Total

Original Cost Pro Forma Original Cost Original Cost Steam Utility To Be Wholesale RetailDescription Depreciated Adjustment Depreciated Adjustments Depreciated Service Allocated Customers Customers

ProductionProduction Equipment 238,802$ (210)$ 238,592$ ‐$ 238,592$ $ 218,184$ Limestone and Other FGD Reagents 2,140 ‐ 2,140 ‐ 2,140 1,957 Total Production 240,942 (210) 240,732 ‐ 240,732 220,141

Transmission Equipment 40,351 ‐ 40,351 ‐ 40,351 40,264

Distribution Equipment 26,520 ‐ 26,520 ‐ 26,520 ‐ ‐ 26,520

Total Plant Materials and Supplies Inventory 307,813$ (210)$ 307,603$ ‐$ 307,603$ $ 286,925$

As Filed

DUKE ENERGY INDIANA, LLCAllocation of Plant Materials and Supplies Inventory to

The Company's Wholesale and Retail CustomersAs of December 31, 2020



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Operation and Maintenance ExpensesProductionFuel 665,530$ (43,457)$ ‐$ 622,073$ ‐$ 622,073$ $ 570,782$ All Other 392,573 (70,290) (39,916) 282,367 ‐ 282,367 255,182 Purchased Power 233,016 (5,938) ‐ 227,078 ‐ 227,078 ‐ 208,862 Total Production 1,291,119 (119,685) (39,916) 1,131,518 ‐ 1,131,518 1,034,826

Transmission 99,337 (3,391) (24,524) 71,422 (2,000) 69,422 69,365 Distribution 127,994 (7,367) (9,129) 111,498 ‐ 111,498 ‐ ‐ 111,498 Customer Accounts 25,189 6,188 ‐ 31,377 ‐ 31,377 ‐ ‐ 31,377 Customer Service and Informational 4,536 (398) ‐ 4,138 ‐ 4,138 ‐ ‐ 4,138 Sales 5,282 (881) ‐ 4,401 ‐ 4,401 ‐ ‐ 4,401 Administrative and General 127,076 (10,855) (10,619) 105,602 ‐ 105,602 100,178 Total Operation and Maintenance Expenses 1,680,533$ (136,389)$ (84,188)$ 1,459,956$ (2,000)$ 1,457,956$ $ 1,355,783$

Depreciation and Amortization 563,526$ 185,156$ ‐$ 748,682$ (12,960)$ 735,722$ $ 693,925$

Taxes Other than Income TaxesPayroll Related 14,307$ (585)$ ‐$ 13,722$ ‐$ 13,722$ $ 12,935$ Property Related 52,107 6,098 ‐ 58,205 ‐ 58,205 55,634 Revenue Related 25,170 (25,170) ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ Total Taxes Other than Income Taxes 91,584$ (19,657)$ ‐$ 71,927$ ‐$ 71,927$ $ 68,569$

Total Operating Expenses Excluding Income Taxes 2,335,643$ 29,110$ (84,188)$ 2,280,565$ (14,960)$ 2,265,605$ $ 2,118,277$


As Filed

DUKE ENERGY INDIANA, LLCAllocation of Operating Revenue Deductions Excluding Income Taxes

To the Company's Wholesale and Retail CustomersFor the Twelve Months Ended December 31, 2020


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Adjusted Updated Electric Total TotalTotal Pro Forma Total Total Steam Utility To Be Wholesale Retail

Description Company Adjustment Company Adjustments Company Service Allocated Customers Customers

Deferred Income Taxes

Federal 36,812$ (24,900)$ 11,912$ 2,588$ 14,500$ $ 16,228$ State 21,237 (11,175) 10,062 (2,941) 7,121 7,127

Total Deferred Income Taxes 58,049$ (36,075)$ 21,974$ (353)$ 21,621$ $ 23,355$

Investment Tax Credit

Production (382)$ ‐$ (382)$ ‐$ (382)$ ‐$ $ $ (350)$

Total Investment Tax Credit (382)$ ‐$ (382)$ ‐$ (382)$ ‐$ $ $ (350)$

As Filed

DUKE ENERGY INDIANA, LLCAllocation of Deferred Income Taxes and Investment Tax Credit

To the Company's Wholesale and Retail CustomersFor the Twelve Months Ended December 31, 2020



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Operating Revenues 2,926,978$ (121,200)$ (84,188)$ 2,721,590$ ‐$ 2,721,590$ $ 2,517,952$

Total Operating Revenue DeductionsOperation and Maintenance Expenses 1,680,533 (136,389) (84,188) 1,459,956 (2,000) 1,457,956 1,355,783 Depreciation and Amortization 563,526 185,156 ‐ 748,682 (12,960) 735,722 693,925 Taxes Other than Income Taxes 91,584 (19,657) ‐ 71,927 ‐ 71,927 68,569 Rate Base Related Interest Charges 198,391 (5,817) ‐ 192,574 (14,879) 177,695 169,889 Parent Company Interest Deduction ‐ 13,095 ‐ 13,095 ‐ 13,095 12,408 Total Operating Revenue Deductions 2,534,034 36,388 (84,188) 2,486,234 (29,839) 2,456,395 2,300,574

Net Income Before Income Taxes 392,944 (157,588) ‐ 235,356 29,839 265,195 217,378

Net Additions / Deductions to Income (284,995) 239,543 ‐ (45,452) (12,958) (58,410) (67,428)

Net Income Before Income Taxes and AfterNet Additions / Deductions to Income 107,949$ 81,955$ ‐$ 189,904$ 16,881$ 206,785$ $ 149,950$

As Filed

DUKE ENERGY INDIANA, LLCCalculation of Current Federal and State Income Tax and

Allocation to the Company's Wholesale and Retail CustomersFor the Twelve Months Ended December 31, 2020



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A B C D E F G H I J K

Petitioner's Exhibit 38‐A (MTD)IURC Cause No. 45253

Schedule 6Page 2 of 2



Calculation of Current State Income TaxNet Income Before Income Taxes and AfterNet Additions / Deductions to Income 107,949$ 81,955$ ‐$ 189,904$ 16,881$ 206,785$ $ 149,950$ Add: State Tax Adjustment (159,539) 23,510 ‐ (136,029) 40,618 (95,411) (83,535) Taxable Net Income for Current State Income Tax (51,590) 105,465 ‐ 53,875 57,499 111,374 66,415

Current State Income Tax (2,773) 5,669 ‐ 2,896 3,090 5,986 3,570 Adjustments to Current State Income Tax (2,109) 2,109 ‐ ‐ ‐ ‐ ‐ ‐ ‐ Total Current State Income Tax (4,882)$ 7,778$ ‐$ 2,896$ 3,090$ 5,986$ $ 3,570$

Calculation of Current Federal Income TaxNet Income Before Income Taxes and AfterNet Additions / Deductions to Income 107,949$ 81,955$ ‐$ 189,904$ 16,881$ 206,785$ $ 149,950$ Deduct: Current State Income Tax (4,882) 7,778 ‐ 2,896 3,090 5,986 3,570 Taxable Net Income for Current Federal Income Tax 112,831 74,177 ‐ 187,008 13,791 200,799 146,380

Current Federal Income Tax 23,695 15,577 ‐ 39,272 2,896 42,168 30,741 Adjustments to Current Federal Income Tax ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ Total Current Federal Income Tax 23,695$ 15,577$ ‐$ 39,272$ 2,896$ 42,168$ $ 30,741$

Total Current Income Tax 18,813$ 23,355$ ‐$ 42,168$ 5,986$ 48,154$ $ 34,311$


As Filed

DUKE ENERGY INDIANA, LLCCalculation of Current Federal and State Income Tax and

Allocation to the Company's Wholesale and Retail CustomersFor the Twelve Months Ended December 31, 2020


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A B C D E F G HPetitioner's Exhibit 38-B (MTD)

IURC Cause No. 45253Schedule 1

TotalOperating

Original Cost Electric Expenses Federal Total NetDepreciated Operating Excluding and State Operating Operating Rate of

Retail Rate Groups Rate Base Revenues Income Taxes Income Taxes Expenses Income Return(Note 1)

Rate RS 4,815,821$ 987,595$ 896,175$ 2,543$ 898,718$ 88,877$ 1.85%

Rate CS and FOC 533,629 122,533 100,263 3,339 103,602 18,931 3.55%

Rate LLF 2,036,842 477,824 395,455 12,114 407,569 70,255 3.45%

Rate HLF 2,645,183 852,482 652,527 39,105 691,632 160,850 6.08%

Special Contracts (Customers L and O) 71,257 49,228 49,807 (470) 49,337 (109) -0.15%

Rate WP 44,893 12,049 10,119 295 10,414 1,635 3.64%

Rates MHLS and SL 8,622 7,849 5,749 481 6,230 1,619 18.78%

Rates UOLS and MOLS 36,168 7,258 7,400 (169) 7,231 27 0.07%

Rates TS, MS and FS 2,778 1,134 781 77 858 276 9.94%

Total Retail 10,195,193$ 2,517,952$ 2,118,276$ 57,315$ 2,175,591$ 342,361$ 3.36%

Note 1) Operating Revenues exclude rents from electric property, sales to other electric companies and miscellaneouselectric revenues. These revenues have been reflected as reductions to operating expenses for purposes ofthe cost of service study.


Duke Energy Indiana, LLCSummary of Net Operating Income and Rate of Return

Under Present Rates for the Company's Retail CustomersBy Rate Group from the Retail Cost of Service StudyFor the Twelve Months Ended December 31, 2020

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A B C D E F G H I J K L M N O P QPetitioner's Exhibit 38-B (MTD)

IURC Cause No. 45253Schedule 2

OPERATING REVENUES LESS: 5.1% OPERATING OVERALLORIGINAL COST REVENUE TOTAL NET AT AVERAGE TOTAL REDUCTION IN PLUS: REVENUE TOTAL PERCENT NETDEPRECIATED OPERATING REMAINING OPERATING OPERATING RATE OF RATE OF SUBSIDY ( ) SUBSIDY ( ) RATE OPERATING REMAINING OPERATING INCREASE OPERATING RATE OF

Retail Rate Groups RATE BASE REVENUE IN RIDERS REVENUE INCOME RETURN RETURN OR EXCESS OR EXCESS INCREASE REVENUE IN RIDERS REVENUE (DECREASE) INCOME RETURN(Note 1)

Rate RS 4,815,821$ 987,595$ 19,435$ 1,007,030$ 88,877$ 1.85% 1,085,036$ (97,441)$ (4,969)$ 171,259$ 1,163,823$ 14,002$ 1,177,825$ 16.96% 219,823$ 4.56%

Rate CS and FOC 533,629 122,533 956 123,489 18,931 3.55% 121,179 1,354 69 18,969 141,433 472 141,905 14.91% 32,978 6.18%

Rate LLF 2,036,842 477,824 3,687 481,511 70,255 3.45% 475,341 2,483 127 72,132 549,829 2,426 552,255 14.69% 123,972 6.09%

Rate HLF 2,645,183 852,482 5,304 857,786 160,850 6.08% 756,135 96,347 4,914 93,614 941,182 6,286 947,468 10.46% 227,061 8.58%

Special Contracts (Customers L and O) 71,257 49,228 (89) 49,139 (109) -0.15% 52,575 (3,347) (171) 2,524 51,923 (235) 51,688 5.19% 1,901 2.67%

Rate WP 44,893 12,049 164 12,213 1,635 3.64% 11,879 170 9 1,593 13,633 138 13,771 12.76% 2,815 6.27%

Rates MHLS and SL 8,622 7,849 7 7,856 1,619 18.78% 6,070 1,779 91 311 8,069 108 8,177 4.09% 1,780 20.64%

Rates UOLS and MOLS 36,168 7,258 148 7,406 27 0.07% 8,848 (1,590) (81) 1,285 8,624 145 8,769 18.40% 1,042 2.88%

Rates TS, MS and FS 2,778 1,134 12 1,146 276 9.94% 889 245 12 101 1,223 11 1,234 7.68% 340 12.24%

Total Retail 10,195,193$ 2,517,952$ 29,624$ 2,547,576$ 342,361$ 3.36% 2,517,952$ -$ 1$ 361,788$ 2,879,739$ 23,353$ 2,903,092$ 13.96% 611,712$ 6.00%

Note 1) Operating Revenues exclude rents from electric property, sales to other electric companies and miscellaneouselectric revenues. These revenues have been reflected as reductions to operating expenses for purposes ofthe cost of service study.

UNDER PRESENT RATES UNDER PROPOSED RATESPRIOR TO SUBSIDY ( ) EXCESS REALLOCATION AFTER SUBSIDY ( ) EXCESS REALLOCATION

Duke Energy Indiana, LLCAssignment of Operating Revenues to the Company's

Retail Customers By Rate Group after the Proposed Rate Increaseand Proposed Reallocation of Subsidy ( ) Excess Revenues between Rate Groups

For the Twelve Months Ended December 31, 2020(Thousands of Dollars)

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PETITIONER'S EXHIBIT 38-C (MTD) IURC Cause No. 45253

Issued: Effective:

Duke Energy Indiana, LLC IURC NO. 15 1000 East Main Street Original Sheet No. 99 Plainfield, IN 46168 Page 1 of 2

REVENUE DECOUPLING MECHANISM (RDM)

1. Provision for Adjustment and Applicability

The base rates per kWh to the nearest 0.001 mills ($0.000001) for electric service set forth in Rate Schedule RS (Residential Electric Service), Rate 6.3 (High Efficiency Residential Service) and Rate CS (Schedule for Commercial Electric Service) shall be adjusted by amounts hereinafter described which amount is referred to as the “Revenue Decoupling Mechanism” (RDM). The RDM shall be calculated, as a charge or credit, and applied to Rate Schedules RS, 6.3, and CS to recover or refund the balance in the Deferred Accounts. The Deferred Accounts shall be established by a monthly adjustment hereinafter described, which monthly adjustments are summed to determine a yearly adjustment for Rate Schedules RS, 6.3, and CS. Customers served on Rider 7.1, Optional High Efficiency Total Electric Commercial service, and Rider 20, YOUR FIXED BILL, are excluded. RDM is a five-year program.

2. Definitions

For purposes of this Adjustment: “Commission” means the Indiana Utility Regulatory Commission.

“Relevant Rate Order” means the final order of the Commission in the most recent rate case of the Company setting the rates of the Company or the most recent final order of the Commission prescribing or setting the factors and procedures to be used in the application of this Adjustment.

3. Computation of the RDM Deferral Accounts for each of the Rate Schedules RS, 6.3 and

CS

RDM Deferral m,g = C m,g X FRC m,g – kWh m,g X FEC g Where:

C m,g = The number of customers billed during month m for customer class g

FRCm,g = The allowed fixed revenue per customer for customer class g in month m as approved in the Company’s most recent general rate case. kWh m,g = Billed sales during month m for customer class g. FEC g = The fixed energy charge for customer class g.

The sum of the monthly RDM Deferrals for a year within Rate Schedules RS (including 6.3) and CS is used to determine the annual RDM dollar adjustment for each rate schedule.

PETITIONER'S EXHIBIT 38-C (MTD) IURC Cause No. 45253

Issued: Effective:

Duke Energy Indiana, LLC IURC NO. 15 1000 East Main Street Original Sheet No. 99 Plainfield, IN 46168 Page 2 of 2

The annual RDM dollar adjustment shall not exceed more than four percent of allowed revenues for each rate class. Deferrals in excess of four percent are carried over to the subsequent year(s) RDM deferral balance computation (or retail rate case.)

4. Computation of the RDM Adjustment for each of the Rate Schedules RS, 6.3 and CS

Effective with bills rendered beginning with the first billing cycle or the effective date of the Commission’s order, if later, the RDM Adjustment to refund or recover the balance in the RDM Deferral Account, shall be calculated to the nearest 0.001 mills ($.000001) by the following formula: RDM Adjustment = Annual RDM dollar adjustment divided by projected annual billed kWh to the applicable customers. Projected and actual recoveries under the RDM are reconciled, with any under or over recovery being recovered or returned over a subsequent twelve-month period.

5. RDM Rates

Retail Rate Class RDM Adjustment Charge/Credit

($ Per kWh) Rate RS, including 6.3 $0.000000 Rate CS $0.000000

Petitioner's Exhibit 38‐D (MTD)

IURC Cause No. 45253

FERC Form No. 1 Production Peaks (page 401b)

January 2013 through June 2018

Month 2018 2017 2016 2015 2014 2013 2012 2011 2010 2009 2008 2007 2006 2005 2004 2003

January 5562 5303 5488 5693 5745 5341 5054 5219 5157 5628 5579 5624 4761 5225 5113 5184

February 5104 4813 5220 5628 5615 5201 4727 5455 5091 5535 5374 5946 4772 4564 4803 4767

March 4511 4809 4586 5307 5045 4712 4389 4475 4552 4794 4810 5238 4530 4638 4220 4620

April 4464 4196 4403 3890 4267 4291 4061 4126 3964 4144 4370 4785 4046 3909 4001 3996

May 5130 4854 5089 4760 4954 4941 5166 5440 5177 4616 4418 5538 5565 4656 5028 4168

June 5756 5524 5699 5387 5491 5357 5971 5611 5566 5657 5565 6101 5733 5874 5400 5208

July Note 2 5516 5828 5748 5436 5808 5992 6159 5733 4975 5755 5749 6450 6255 5660 5410

August Note 2 5588 6002 5413 5685 5772 5772 5864 6010 5559 5607 6282 6282 5925 5618 5827

September Note 2 5692 5852 5638 5829 5877 5365 5873 5368 4594 5823 6368 4692 5316 5030 4873

October Note 2 4614 4704 4123 4277 4593 4108 4107 4252 4056 4522 5423 4754 5050 3923 3894

November Note 2 4433 4350 4303 5005 4625 4516 4517 4506 4358 4638 4781 4537 4500 4204 4411

December Note 2 5184 5472 4474 4734 5235 4658 4679 5395 5154 5288 5817 8288 5177 4954 4585

Note 1: Peaks in bold are the 4 highest peaks on a calendar year basis as reported on the FERC Form No. 1 for years 2003 ‐ 2017

Note 2: 12 months ended June 2018 was the COSS cut‐off, resulting in August 2017, September 2017,

January 2018 and June 2018 as the highest 4 months used in the 2019 base rate case (shaded).

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VERIFICATION

I hereby verify under the penalties of perjury that the foregoing representations arc true to the best of my knowledge, information and belief.

Signed: ~ J, 7) ).0.. 2:: Dated: I;) - 4 - ;).cL-°J Maria T. Diaz

REBUTTAL TESTIMONY OF MARIA T. DIAZ DIRECTOR, RATES …

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