VIA ELECTRONIC CASE FILING

Clark Hill PLC

212 East César E. Chá vez Avenue

Lansing, Michigan 48906

Bryan A. Brandenburg T 517.318.3100

T 517.318.3011 F 517.318.3099

F 517.318.3099

Email: [email protected] clarkhill.com

216986985.1 07411/321230

February 28, 2018

VIA ELECTRONIC CASE FILING

Ms. Kavita KaleExecutive SecretaryMichigan Public Service Commission7109 W. Saginaw HighwayLansing, Michigan 48917

Re: MPSC Case No. U-18424: In the matter of the Application of ConsumersEnergy Company for authority to increase its rates for the distribution ofnatural gas and for other relief.

Dear Ms. Kale:

Enclosed for filing is the Direct Testimony and Exhibits of Jeffry Pollock and the DirectTestimony and Exhibits of Billie S. LaConte, on behalf of the Association of BusinessesAdvocating Tariff Equity, along with a Proof of Service in the above referenced case.

Sincerely,

CLARK HILL PLC

Bryan A. Brandenburg

BAB/jmj

cc w/enc.: Parties of RecordALJ Suzanne D. Sonneborn

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the application ofCONSUMERS ENERGY COMPANY forauthority to increase its rates for thedistribution of natural gas and for other relief.

§§§§§

Case No. U-18424

Direct Testimony and Exhibits

of

Jeffry Pollock

On Behalf of

Association of Businesses Advocating Tariff Equity

February 28, 2018

Jeffry PollockDirectPage i

J . P O L L O C KI N C O R P O R A T E D

STATE OF MICHIGAN


In the matter of the application ofCONSUMERS ENERGY COMPANY forauthority to increase its rates for thedistribution of natural gas and for other relief.

§§§§§

Case No. U-18424

Table of Contents

LIST OF EXHIBITS ............................................................................................................... ii

GLOSSARY OF ACRONYMS .............................................................................................. iii

1. INTRODUCTION, QUALIFICATIONS AND SUMMARY.................................................. 1

Summary.....................................................................................................................2

2. CLASS COST-OF-SERVICE STUDY.............................................................................. 5

Average and Peak Method ..........................................................................................7

Distribution Mains......................................................................................................14

Storage ....................................................................................................................22

Revised Class Cost-of-Service Study........................................................................26

3. TRANSPORTATION RATE DESIGN .............................................................................29

4. CONCLUSION ...............................................................................................................31

APPENDIX A.......................................................................................................................32

APPENDIX B.......................................................................................................................34

APPENDIX C ......................................................................................................................52

Jeffry PollockDirectPage ii


LIST OF EXHIBITS

Exhibit Description

AB-1 Derivation of Peak Day Design

AB-2 Revised Average & Peak Allocation Factors

AB-3 Predominant Size Method: Distribution Mains

AB-4 Revised Gas Class Cost-of-Service Study – Version 2

AB-5 Calculation of Rate Design Targets

Jeffry PollockDirectPage iii


GLOSSARY OF ACRONYMS

Term Definition

A&P Average and Peak

ABATE Association of Businesses Advocating Tariff Equity

AT Annual Throughput

ATL Authorized Tolerance Level

ASLF Annual System Load Factor

CCOSS Class Cost-of-Service Study

Consumers Consumers Energy Company

CSQ Contract Storage Quantity

Dth dekatherms

EUT End-Use Transportation

HDD Heating Degree Day

LDC Local Distribution Company

LIA Low Income Assistance

MW Megawatt

NARUC National Association of Regulatory Utility Commissions

O&M Operation and Maintenance

PDD Peak Day Design

RIA Residential Income Assistance

WAWDD Wind Adjusted Weighted Degree Days

Jeffry PollockDirectPage 1

1. Introduction, Qualificationsand Summary


Direct Testimony of Jeffry Pollock

1. INTRODUCTION, QUALIFICATIONS AND SUMMARY

Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.1

A Jeffry Pollock; 12647 Olive Blvd., Suite 585, St. Louis, MO 63141.2

Q WHAT IS YOUR OCCUPATION AND BY WHOM ARE YOU EMPLOYED?3

A I am an energy advisor and President of J. Pollock, Incorporated.4

Q PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE.5

A I have a Bachelor of Science Degree in Electrical Engineering and a Master’s6

Degree in Business Administration from Washington University. For over 40 years, I7

have been engaged in a variety of consulting assignments, including energy8

procurement and regulatory matters in both the United States and several Canadian9

provinces. My qualifications are documented in Appendix A. A partial list of my10

appearances is provided in Appendix B to this testimony.11

Q ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?12

A I am appearing on behalf of the Association of Businesses Advocating Tariff Equity13

(ABATE), a group of businesses including many of Michigan’s largest employers that14

are large energy customers of Consumers Energy Company (Consumers). ABATE15

members are large gas consumers that transport their gas supplies through16

Consumers under the rates, terms and conditions of Consumers’ Transportation17

Service Rate.18




Q WHAT IS THE PURPOSE OF YOUR TESTIMONY?1

A I address Consumers’ class cost-of-service study, class revenue allocation and the2

design of the Transportation Service Rate. My colleague, Ms. Billie S. LaConte, will3

address Consumers’ proposed return on common equity and capital structure.4

Q ARE YOU SPONSORING ANY EXHIBITS WITH YOUR TESTIMONY?5

A Yes. I am sponsoring Exhibit AB-1 through AB-5. These exhibits were prepared6

by me or under my supervision and direction.7

Q ARE YOU ACCEPTING CONSUMERS’ POSITIONS ON THE ISSUES THAT ARE8

NOT ADDRESSED IN YOUR DIRECT TESTIMONY?9

A No. Additionally, throughout my testimony, I use Consumers’ proposed revenue10

requirements to illustrate certain cost allocation and rate design principles. These11

illustrations should not be interpreted as an endorsement of Consumers’ proposals.12

Summary13

Q PLEASE SUMMARIZE YOUR FINDINGS AND RECOMMENDATIONS.14

A My findings and recommendations are as follows:15

Class Cost-of-Service Study

• Consumers’ class cost-of-service study inappropriately uses peak16month (i.e., January) throughput rather than a peak demand metric to17allocate a portion of transmission mains, storage, and distribution18mains.19

• There are accepted methods to derive a peak demand metric from20peak month throughput.21

• Consumers’ gas delivery system must be sized to meet the Peak Day22Design in order to provide reliable gas sales and delivery services.23Peak Day Design is also important in determining how Consumers’24manages its vast gas storage facilities. Accordingly, Peak Day25




Design should be used instead of peak month throughput in allocating1the costs of transmission mains, storage, and distribution mains.2

• Consumers’ class cost-of-service study does not recognize any3portion of distribution mains as a customer-related cost. This is4contrary to accepted practice and precedent established by many5state regulatory commissions.6

• Ignoring any customer-related component of distribution mains results7in under-stating the costs of mains allocated to residential customers8and over-stating the allocated costs to large transportation customers.9

• Ignoring any customer-related component of distribution mains is also10contrary to cost-causation because gas utilities must make minimum11investments in facilities, including distribution mains and service12laterals, just to connect a customer to the gas delivery system that is13completely independent of the level of the peak demand and annual14usage of the customer. Further, this investment must be capable of15sustaining the appropriate operating pressure to support the delivery16of natural gas. These two functions (connection and deliverability)17clearly demonstrate the customer-related nature of distribution mains.18

• A portion of distribution mains should be allocated on a customer19basis.20

• Consumers’ allocation of storage costs is also not consistent with21cost-causation for three reasons.22

o First, Consumers inappropriately used peak month throughput23rather than Peak Day Design.24

o Second, Consumers uses a “utilization” study, which25measures the amount of gas cycled (that is, the quantity of gas26injected and withdrawn) over a twelve month period.27However, the amount of gas cycled does not directly measure28the variations in gas deliveries and gas usage, which29determines the amount of storage used by transportation30customers. Further, the utilization study was limited to31allocating costs between the gas sales and transportation rate32groups. Within these groups, utilization was defined by annual33gas throughput.34

o Third, the assumed 50%/50% split between peak demand and35utilization appears to under-state the importance of storage in36maintaining system reliability on the critical heating days.37

• Further, Consumers should be ordered to conduct a detailed study of38how transportation customers use storage. The results of this study39should be presented in the next rate case.40

• Consumers’ class cost-of-service study should be modified as follows:41




o Peak Day Demand should replace peak month throughput in1applying the Average and Peak method and to allocate the250% of storage costs that were allocated on peak month3throughput.4

o 25% of distribution mains investment should be allocated on5the number of customers, rather than the Average and Peak6method. This is based on a partial application of the7Predominant Size method, which uses the cost of 2 inch8plastic pipe installed over the past ten years as a percent of all9distribution mains installed.10

• The results of the revised class cost-of-service study should be used11to determine an appropriate class revenue allocation; that is, how any12base revenue increase should be spread among the various customer13classes. Specifically, the rates charged to the gas sales and14transportation rate groups should be adjusted to reflect each group’s15allocated costs.16

• The class revenue allocation should also recognize the principle of17gradualism; that is, no class should receive an increase higher than1825% and no class should receive a rate decrease.19

Rate Design

• Consumers is proposing a new transportation rate (XXLT) for20extremely large transportation customers. In connection with this21proposal, Consumers is offering Rate XXLT customers the option of a224% Authorized Tolerance Level.23

• There is no reason not to extend the 4% Authorized Tolerance Level24to Rate XLT customers, because they have similar usage25characteristics as Rate XXLT customers, and providing an option for a26lower Authorized Tolerance Level would send a more proper price27signal and provide a stronger incentive for Rate XLT customers to28more closely manage their gas supply imbalances.29


2. Class Cost-of-Service StudyJ . P O L L O C KI N C O R P O R A T E D

2. CLASS COST-OF-SERVICE STUDY

Q WHAT IS A CLASS COST-OF-SERVICE STUDY?1

A A class cost-of-service study (CCOSS) is an analysis used to determine each class’s2

responsibility for a utility’s costs. Thus, it determines whether the revenues a class3

generates covers the class’s cost of service. A CCOSS separates a utility’s total4

costs into portions incurred on behalf of each customer class. Most of a utility’s5

costs are incurred jointly to serve many customers. For purposes of revenue6

allocation and rate design, customers are grouped into homogenous classes7

according to their usage patterns and service characteristics. The procedures8

typically used in a CCOSS are described in more detail in Appendix C.9

Q HAS CONSUMERS CONDUCTED A CLASS COST-OF-SERVICE STUDY IN THIS10

PROCEEDING?11

A Yes. Consumers presented two CCOSSs. The first study was based on the existing12

customer class definitions. The second study included a proposed new pilot13

transportation tariff, Rate XXLT.14

Q DO CONSUMERS’ CLASS COST-OF-SERVICE STUDIES COMPORT WITH15

ACCEPTED INDUSTRY PRACTICES.16

A Generally, yes. The studies recognize the different types of costs, the different ways17

natural gas is delivered to customers and how certain customers use Consumers to18

transport and deliver the natural gas that these customers self-supply (i.e.,19

transportation service). However, there are three material flaws with the CCOSSs20

that do not comport with accepted industry practices.21



First, Consumers’ application of the Average and Peak (A&P) method is1

flawed because it uses January gas throughput instead of peak demand to allocate2

the vast majority of transmission and distribution plant-related costs. Thus,3

Consumers’ A&P method is, in reality, the Average and January Average method.4

Although I disagree with A&P, a proper application of A&P should include a peak5

demand metric, such as Peak Day Design (PDD), which Consumers uses for6

planning purposes.7

The second material flaw is that Consumers classifies distribution mains as8

demand and commodity-related costs. No distribution mains costs are classified as9

customer-related. The failure to recognize a customer-related portion of distribution10

mains costs ignores the realities of a gas delivery system; that is, a utility must make11

a minimum investment in delivery facilities (mains and service laterals) just to attach12

a customer to the system and to provide deliverability before any gas service can be13

provided. Accordingly, as detailed later, a portion of the costs of distribution mains14

should be classified as customer-related.15

The third material flaw is that Consumers’ proposed allocation of storage16

plant uses an arbitrary 50%/50% split between storage utilization and January17

throughput. As with the A&P method, using the January throughput is an improper18

metric for measuring peak demand. Accordingly, PDD should be used instead of19

January throughput as the metric for peak demand. Further, the allocation assumes20

that transportation customers use storage to the same degree as sales customers21

during the withdrawal season (typically, the months November through March)22

notwithstanding the specific limitations specified in the tariff. However, Consumers23

does not have the data necessary to quantify how end-use transportation (EUT)24



customers actually utilize storage. Consequently, Consumers should conduct an in-1

depth study of its EUT customers to determine how they utilize storage.2

Average and Peak Method

Q WHAT IS THE AVERAGE AND PEAK METHOD?3

A The standard A&P method allocates a portion of plant-related costs using annual4

throughput, while the remaining costs are allocated using a peak demand metric.5

The standard formula for A&P as published by the National Association of Utility6

Regulatory Commissioners (NARUC) is set forth below.7

�&� = �� + ��(1 − ��)8

Where: AT = Annual Throughput9ASLF = Annual System Load Factor10PD = Peak Demand.11

However, as previously explained, Consumers’ application of A&P uses January12

2019 throughput instead of a peak demand metric. Further, Consumers used PDD13

demand to derive the ASLF.1 This inconsistency further underscores the flaws with14

Consumers’ application of A&P.15

Q WHY DO YOU ASSERT THAT USING A PEAK DEMAND METRIC IS16

APPROPRIATE?17

A First, a peak demand metric is consistent with cost-causation because it recognizes18

the utility’s obligation to serve. The obligation to serve means providing facilities that19

are appropriately sized to meet the expected peak demand for natural gas. Sizing20

the facilities to meet peak demand will ensure that there is sufficient capacity to21

supply natural gas on the coldest days of the year, when the utility experiences its22

1 The ASLF for storage costs is 50%.



maximum heating loads. Once in place to serve peak demand, the facilities can be1

used to meet customer needs throughout the year.2

Second, the NARUC description of A&P specifically references a peak3

demand metric. For example:4

d. Average and Peak Demand Method5

This method reflects a compromise between the coincident and6noncoincident demand methods. Total demand costs are multiplied7by the system's load factor to arrive at the capacity costs attributed to8average use and are apportioned to the various customer classes on9an annual volumetric basis. The remaining costs are considered to10have been incurred to meet the individual peak demands of the11various classes of service and are allocated on the basis of the12coincident peak of each class.2 (Emphasis added)13

Q IS JANUARY THROUGHPUT A REASONABLE PEAK DEMAND METRIC?14

A No. Consumers projects that its test-year peak demand would occur in January.15

However, January throughput represents the average amount of gas used during the16

entire month. For example, Consumers projected January 2019 gas requirements of17

47,332 MMcf, which is approximately 1,527 MMcf per day (47,332 MMcf ÷ 31 days).318

However, Consumers’ 2017 PDD demand was 3,485 MMcf.4 Consumers could not19

meet a 3,485 MMcf demand if its delivery system was only sized to supply 1,52720

MMcf of gas on the peak day.21

Q WHAT PEAK DEMAND METRIC SHOULD BE USED TO ALLOCATE THE22

DEMAND-RELATED COSTS UNDER THE A&P METHOD?23

A Demand-related costs should be allocated to customer classes on the basis of PDD24

2 National Association of Regulatory Utility Commissioners, Gas Distribution Rate Design Manual at27-28 (June 1989).

3 Direct Testimony of Luis F. Saenz, WP-LFS-17.

4 Id.



demand. Consumers defines the PDD demand as follows:1

The peak day design requirement, also referred to as a design peak2day, is the total maximum daily load for all gas customers that3Consumers Energy would expect to serve under the most extreme4cold weather conditions. Those extreme cold weather conditions are5defined in Wind Adjusted Weighted Degree Days (“WAWDD”). Thus,6the Company’s peak day design requirements reflect the lowest7average daily temperature and highest daily load planned to be8served on a given day in a given month.59

PDD demand, thus, determines how both transmission and distribution mains should10

be sized in order to provide reliable gas delivery service. PDD is also a critical factor11

in determining how Consumers manages its gas storage facilities to ensure that12

there are ample supplies of natural gas available to meet demand during the critical13

peak heating period.14

Q DOES CONSUMERS USE PEAK MONTH THROUGHPUT IN ALLOCATING15

EITHER ELECTRIC PRODUCTION OR DISTRIBUTION PLANT AND RELATED16

EXPENSES?17

A No. In its most recent electric rate case, Consumers used a version of A&P to18

allocate production demand-related costs. Specifically, peak demand was weighted19

75% and annual throughput was weighted 25%. The peak demand metric was the20

four coincident peak method. Distribution plant was allocated using class peak21

demand. Thus, peak month throughput was not used.22

5 In the matter of the application of CONSUMERS ENERGY COMPANY for approval of a gas costrecovery plan and authorization of gas cost recovery factors for the 12-month period April 2017 –March 2018, Docket No. U-18151, Direct Testimony of Jonathon J. Guscinski at 12. (Dec. 2016)Hereinafter referred to as “2017-18 GCR Filing.”



Q IS IT APPROPRIATE TO USE PEAK MONTH THROUGHPUT AS A PROXY FOR1

THE SYSTEM PEAK DEMAND?2

A No. For all of the above reasons, PDD demand (rather than January throughput)3

should be the peak demand metric used in applying the A&P method.4

Q WHY DOES CONSUMERS USE JANUARY THROUGHPUT RATHER THAN A5

SPECIFIC PEAK DEMAND METRIC?6

A Consumers states that it does not have the necessary metering in place to measure7

each class’s contribution to the peak day.68

Q IF CONSUMERS DOESN’T HAVE ADEQUATE METERING, HOW CAN THE9

PEAK DAY DESIGN DEMANDS BE DERIVED FOR EACH CUSTOMER CLASS?10

A Exhibit AB-1 provides a statistical methodology for calculating a Peak Day Design11

amount from the January (peak month) throughput. This methodology is illustrated in12

the NARUC Gas Distribution Rate Design manual.7 Specifically, the methodology13

derives the daily temperature-sensitive gas usage by customer class and assumes a14

linear correlation between the temperature-sensitive gas usage and the heating15

degree days (HDDs) on the PDD.16

Q ARE YOU AWARE OF ANY UTILITIES THAT HAVE USED THIS METHODOLOGY17

WHEN ADEQUATE METERING IS NOT AVAILABLE?18

A Yes. For example, Central Hudson Gas & Electric Corporation and Niagara Mohawk19

Power Corporation have used the same statistical methodology for calculating a20

6 Consumer’s Response to 18424-AB-CE-240.

7 National Association of Regulatory Utility Commissioners, Gas Distribution Rate Design Manual at48. (June 1989)



PDD amount in all of their recent gas delivery rate cases.1

Q PLEASE EXPLAIN THE METHODOLOGY.2

A The first step is to quantify the average monthly and daily use per customer during3

the peak month, which is January 2019. This is shown in Exhibit AB-1 in columns4

1-4. The annual daily use per customer is shown in column 5. Second, the base5

period average monthly use per customer is quantified in columns 6-9. The base6

period represents non temperature-sensitive gas usage. For Consumers, the base7

period represents the months of July and August.8

The third step is to calculate the heating load per customer and per HDD.9

The heating load per customer is shown in column 10 and the heating load per HDD10

is quantified in column 11. During the test year, January sales were based on 1,14311

HDD.812

Fourth, the average daily gas usage per HDD (column 12) is derived using13

Consumers’ design day planning criteria of 75 HDD.9 This value is extrapolated for14

each customer class based on the number of customers (column 13).15

The final step is to reconcile the sum of the derived design day heating usage16

by customer classes to the total projected design day usage (column 14). The17

resulting PDD allocation factors are shown in column 15 and summarized in the table18

below.19

8 Consumers’ Response to AB-CE-439.

9 Id.



Peak Day Design VersusJanuary (Peak Month) Throughput

Allocation Factors

Rate GroupCustomer

ClassPeak DayDesign

JanuaryThroughput

Gas Sales

Residential 61.92% 59.13%

Rate GS-1 9.44% 9.09%

Rate GS-2 11.84% 11.45%

Rate GS-3 2.32% 2.33%

Transportation

Rate ST 4.02% 4.64%

Rate LT 3.08% 3.91%

Rate XLT 5.77% 7.06%

Rate XXLT 1.61% 2.39%

Total 100.00% 100.00%

Also shown are the January throughput allocators used by Consumers. As can be1

seen, Consumers’ method allocates significantly more costs to the transportation2

rate group, which, as proposed, consists of the ST, LT, XLT and XXLT customer3

classes.4

Q HAVE YOU CALCULATED REVISED A&P ALLOCATION FACTORS USING THE5

PEAK DAY DESIGN ALLOCATION FACTORS AS SHOWN IN EXHIBIT AB-1?6

A Yes. The revised A&P allocation factors are derived in Exhibit AB-2. The A&P7

allocator for transmission costs is derived on pages 1 and 2. The corresponding8

A&P allocators for distribution mains are shown on pages 3 and 4, and the revised9

A&P allocation factors for storage are shown on page 5. All of the calculations10

presented in Exhibit AB-2 are based on the same assumptions used by Consumers.11

Consistent with the A&P formula (see page 7), PDD demand was weighted by one12



minus the ASLF for transmission and distribution mains and 50% for storage. I1

discuss the 50% weighting applied to storage below.2

Q IS THERE ANY PRECEDENT FOR USING PEAK DAY DESIGN ALLOCATING3

DISTRIBUTION MAINS?4

A Yes. For example, A&P has previously been approved by the Illinois Commerce5

Commission. In these instances, the peak demand metric was either the peak6

design day or the annual system peak day. Design day was also approved for7

utilities in Iowa and Pennsylvania.108

Q WHAT DO YOU RECOMMEND?9

A PDD demand (and not January throughput) should be used as the “peak” metric in10

applying A&P. PDD is used by Consumers and many gas delivery companies for11

planning purposes to determine the size of the facilities required to provide reliable12

gas delivery service, particularly on those coldest days of the year when the demand13

for natural gas is at its highest. Further, using a PDD demand metric is also14

consistent with how A&P is applied by those gas delivery companies and state15

regulatory commissions that have approved A&P. Accordingly, the Commission16

should replace January throughput with the PDD demand metric in the allocation of17

transmission, distribution and storage plant-related costs in this proceeding.18

10 Northern Illinois Gas Company d/b/a Nicor Gas Company Proposed General Increase inGas Rates and Revisions to Other Terms and Conditions of Service, Order at 110, 115 (Jan.31, 2018). See Also: 1993 WL 344299 (Iowa U.B.) Re Iowa Elec. Light & Power Co., RPU-92-9, 1993 WL 344299 (July 19, 1993); and, 73 Pa.P.U.C. 301, 1990 WL 10702755(Pa.P.U.C.) Pennsylvania Pub. Util. Comm'n, 73 Pa. P.U.C. 301 (Nov. 21, 1990).



Distribution Mains

Q. WHAT ARE DISTRIBUTION MAINS?1

A. Distribution mains are the various pipes used to deliver natural gas to end-use2

customers. The associated costs are typically booked to FERC Account No. 376.3

Q HOW IS CONSUMERS PROPOSING TO CLASSIFY AND ALLOCATE GAS4

DISTRIBUTION MAINS?5

A Consumers is proposing that high and low pressure gas distribution mains be6

classified as both demand and commodity-related costs. The commodity-related7

portion of distribution mains is weighted by the ASLF, while the demand-related8

costs are weighted by one minus the ASLF. The annual system load factor is the9

total throughput divided by the product of system PDD demand and 365 days. No10

distribution mains were classified as customer-related costs.11

Q IS IT APPROPRIATE TO CLASSIFY THE COSTS OF DISTRIBUTION MAINS12

ENTIRELY ON A DEMAND/COMMODITY BASIS, AS CONSUMERS PROPOSES?13

A No. A 100% demand classification of distribution mains is inappropriate and is14

inconsistent with accepted practice in many jurisdictions.15

Q WHY SHOULD A PORTION OF DISTRIBUTION MAINS COSTS BE CLASSIFIED16

AS CUSTOMER-RELATED?17

A Gas utilities must make minimum investments in facilities, including distribution18

mains and service laterals, just to connect a customer to the gas delivery system that19

is completely independent of the level of the peak demand of the customer. Further,20

this investment must be capable of sustaining the appropriate operating pressure to21

support the delivery of natural gas. To the extent that this component of distribution22



mains costs is a function of the requirement to connect the customer and support the1

deliverability of natural gas, regardless of the customer’s size, it is appropriate and2

consistent with cost-causation to allocate the cost of those facilities to service3

classes based on the number of customers.4

Q IS THE ALLOCATION OF DISTRIBUTION MAINS COSTS ON A CUSTOMER AND5

DEMAND BASIS CONSISTENT WITH ACCEPTED REGULATORY PRACTICE?6

A Yes. The NARUC Gas Rate Design and Gas Distribution Rate Design manuals7

discuss several methodologies and approaches to cost allocation. With respect to8

the allocation of distribution mains costs, the NARUC Manual states:9

A portion of the costs associated with the distribution system may10be included as customer cost.1111

The Manual further states:12

One argument for inclusion of distribution related items in the13customer cost classification is the “zero [inch] or minimum size main14theory.”1215

Similarly, the Manual indicates that the cost associated with distribution mains is16

typically functionalized on a demand and customer basis.1317

Q. HAVE OTHER STATE COMMISSIONS SUPPORTED A CUSTOMER18

COMPONENT OF DISTRIBUTION MAINS?19

A. Yes. About half of state regulatory commissions recognize both a customer and a20

demand-related component of distribution mains. In particular, the state of Arkansas21

11 National Association of Regulatory Utility Commissioners, Gas Distribution Rate Design Manual at22 (June 1989).

12 Id.

13 National Association of Regulatory Utility Commissioners, Gas Rate Design manual at 28. (Aug. 6,1981)



recently enacted Act 725 requiring the use of 2-inch mains in determining the1

customer-related component of distribution mains. Act 725 identifies the following2

methodologies for determining the customer-related portion of distribution mains3

costs:4

• USOA numbers 374 through 376 and related depreciation, return on5investment, property insurance and taxes (excluding state and federal6income taxes), fixed operation and maintenance expense charged to7USOA numbers 870-894. The cost of the predominant size main8installed by the utility that is at least two inches in diameter.9

• USOA numbers 377 through 387: A study that reflects the10investments required to meter, regulate, and connect each class of11customers to the gas utility’s system.1412

The Arkansas Public Service Commission must find that using these methodologies13

will be beneficial to economic development or the promotion of employment14

opportunities and will result in just and reasonable rates for all classes of customers.15

Q. HAVE OTHER REGULATORY COMMISSIONS RECOGNIZED THAT THERE IS A16

CUSTOMER COMPONENT OF DISTRIBUTION MAINS FOR COST ALLOCATION17

PURPOSES?18

A. Yes. For example, the Connecticut Public Utilities Regulatory Authority reasoned19

that:20

The investment an LDC makes in mains is clearly dependent upon 1)21the number of customers served and 2) the maximum coincidental22demand or combined demand of all customers on the peak day.23Main extensions consist of two distinct cost activities. First, there is24the cost associated with the trench required to reach customers.25These costs consist of digging, laying a proper bed, back-filling,26tamping, and asphalt patching. The second cost relates to the size27of main installed where size is determined exclusively by the28coincidental peak period demand of present and future users...In29accordance with an engineering replication theory of cost30

14 Act 725 of 2015, Ark. Code Ann. § 23-4-422(b)(3). Note that Acct. No. 874 is Distribution Mains.



responsibility, the Department believes that the classification of1mains into a demand and customer component using the zero-2intercept method is most appropriate.153

A similar policy has received long-standing approval by the New York State4

Public Service Commission. For example, in a 2008 Central Hudson Gas and5

Electric Company rate case, the New York Commission adopted the Administrative6

Law Judge’s recommendation for the continued use of the Zero-Intercept method,7

and it rejected Staff’s proposal to allocate gas mains costs entirely to demand. The8

Order stated:9

Staff proposed to reclassify gas distribution main costs for purposes of10the pro forma embedded cost of service study by assigning them11entirely to the demand component of rates. Currently, based on the12zero-intercept methodology that Central Hudson has used since at13least 1990, those costs are classified 55% to the customer component14of rates and only 45% to the demand component. Because gas15mains constitute 20% of the total cost of gas service, the16reclassification results in a very large shift in cost responsibility from17residential customers to large gas users. The RD [Recommended18Decision] noted that both the existing and proposed methodologies19are deemed acceptable by NARUC with no indication that one or the20other is superior. It concluded that such a large shift in cost21responsibility should not be adopted without compelling evidence that22it is necessary to rectify some serious inequity…We have stated23repeatedly that we strive to match cost responsibility with cost24causation…At the same time, as we discuss in connection with25customer charges and the common cost allocation ratio, we have26consistently taken a gradual approach when a sudden, full correction27would create unacceptable bill impacts. That situation clearly exists28here. Finally, although we find the arguments persuasive as to the29assignment of a greater proportion of gas mains costs to the demand30component, we are not convinced on this record that no mains costs31should be classified as customer related. Accordingly, we direct that32for the purpose of setting rates in this case, the allocation of gas33mains costs should be 65% demand and 35% customer. This is34

15 DPUC Review of Natural Gas Companies Cost of Service Study Methodologies, Docket No. 99-03-28, Decision at 9-10. (Aug. 2000)



consistent with the ratio that we adopted for National Grid in1approving a Joint Proposal in its recent gas rate case.162

Q ARE THE PREDOMINANT SIZE AND ZERO-INTERCEPT METHODS SIMILAR?3

A Yes. The Predominant Size approach identifies the minimum sized distribution4

mains needed to serve customers and then classifies that portion of distribution5

mains as customer-related. Zero-Intercept uses regression analysis to identify the6

cost of a hypothetical “zero sized” main, the cost of which is necessary to serve7

customers connected to the system whether or not they place any demand on the8

system. While there may be subtle differences between the two methods, both9

recognize that certain distribution mains costs should be classified as customer-10

related and allocated based on the number of customers and not on peak demand.11

Q WHAT IS THE RESULT OF FAILING TO RECOGNIZE A CUSTOMER-RELATED12

COMPONENT IN THE COST OF DISTRIBUTION MAINS?13

A The result is a misallocation of costs that fails to allocate proper cost responsibility to14

the various customer classes. The inequity of classifying no gas distribution mains15

as customer-related can be illustrated by the following example.16

Assume there is a single industrial customer on Consumers’ system with a17

peak demand of 500 dekatherms (Dth). Further, assume that elsewhere on the18

system there is a neighborhood of 1,000 residential customers with an aggregated19

peak demand of 500 Dth. It is obvious that in order to connect all of those residential20

customers to the system, Consumers would have to invest in far more footage of21

16 Proceeding on Motion of the Commission as to the Rates, Charges, Rules and Regulations ofCentral Hudson Gas & Electric Corporation for Electric and Gas Service, Case Nos. 08-E-0887, 08-G-0888, 09-M-0004, Order Adopting Recommended Decision with Modifications at 46-48 (June2009). See also, Case Nos. 08-E-0887, 08-G-0888, 09-M-0004, supra, Recommended Decision at104-107 (Apr. 2009).



distribution mains for those customers than it would have to invest in for the one1

industrial customer. That extra investment in distribution mains is due solely to the2

number of customers on the system, not the peak demand of those customers.3

Q WHAT IS THE PRACTICAL EFFECT OF CLASSIFYING ALL GAS DISTRIBUTION4

MAINS COSTS BETWEEN DEMAND AND COMMODITY?5

A The practical effect is to drastically under-allocate distribution mains costs to6

residential gas sales customers and drastically over-allocate these costs to large7

transportation customers. This is demonstrated in the table below, which shows the8

average length of distribution mains allocated to each customer class using9

Consumers’ A&P allocation factors. I then divided the results by the number of10

customers to derive the average length of distribution mains serving each customer.11

The table below summarizes the results of my analysis.12



Impact of Not RecognizingA Customer-Related Component

of Distribution Mains

CustomerClass

A&PAllocation

Factor

Avg. Lengthper

Customer

Residential 62.97% 56

Rate GS-1 9.44% 118

Rate GS-2 11.83% 1,468

Rate GS-3 2.30% 8,905

Rate ST 4.77% 4,989

Rate LT 3.16% 7,226

Rates XLT/XXLT 5.54% 59,634

Q WHAT DOES THE TABLE DEMONSTRATE?1

A The table demonstrates that Consumers’ allocation method yields unrealistic results.2

For instance, not recognizing any customer-related component of mains approach3

suggests that Consumers must install nearly 60,000 linear feet (over 11 miles) of gas4

distribution mains to serve each and every large transportation (XLT and XXLT)5

customer. In stark contrast, Consumers needs to only install 56 linear feet of mains6

to serve each Residential customer. To put this in perspective, the Company allows7

residential customers up to 1,800 feet per installation for service lines installed under8

Consumers’ Service Line Limit policy.17 Distribution mains require a much more9

extensive investment than service laterals. For this reason, each residential10

customer should require more than 56 linear feet of mains. This disparity11

demonstrates how failing to classify any distribution mains costs as customer-related12




is not consistent with either cost-causation or the physical realities of a gas1

distribution system.2

Q HAVE YOU ESTIMATED THE PORTION OF DISTRIBUTION MAINS THAT3

SHOULD REPRESENT A CUSTOMER-RELATED COST?4

A Yes. Exhibit AB-3 shows the application of the Predominant Size method to5

Consumers. For Consumers, the predominant size main is 2-inch plastic pipe.186

Over the past ten years, Consumers has installed about 12.7 million linear feet of7

distribution mains (line 21, column 21) at a total cost of $387.1 million (line 21,8

column 22). This equates to an average installed cost of $30.42 per linear foot (line9

22, column 22). During the same period, Consumers installed 8.1 million linear feet10

of 2-inch plastic pipe (line 23, column 21) at a total cost of $143 million (line 23,11

column 22). This translates into an average installed cost of $17.66 per linear foot12

(line 24, column 22). Thus, the Predominant Size method would classify13

approximately 58% ($17.66 ÷ $30.42) of distribution mains as customer-related, as14

shown on line 25.15

Q PLEASE SUMMARIZE YOUR ANALYSIS OF DISTRIBUTION MAINS.16

A Applying the Predominant Size method would result in classifying approximately 58%17

of distribution mains as a customer-related cost. Accordingly, there should be some18

recognition of a customer-related component of mains in the CCOSS.19




Storage

Q HOW ARE STORAGE-RELATED COSTS BEING ALLOCATED IN CONSUMERS’1

CLASS COST-OF-SERVICE STUDY?2

A Consumers allocates 50% of storage plant and related expenses on storage3

utilization and 50% on January throughput.4

Q DO YOU HAVE ANY CONCERNS WITH HOW CONSUMERS ALLOCATES5

STORAGE-RELATED COSTS?6

A Yes, I have three concerns.7

Q WHAT IS YOUR FIRST CONCERN?8

A As with the A&P method that Consumers used to allocate transmission and9

distribution mains, Consumers is proposing to use January throughput rather than10

PDD demand for allocating storage. January throughput is not an accurate measure11

of peak demand, as previously discussed.12

Q WHAT IS YOUR SECOND PRIMARY CONCERN WITH HOW CONSUMERS13

ALLOCATES STORAGE-RELATED COSTS?14

A Consumers defines storage utilization based on the amount of gas cycled (that is,15

the quantity of gas injected and withdrawn) over a twelve month period. However,16

the volumes of gas cycled do not directly measure the magnitude or timing of any17

gas supply imbalances by EUT customers that could result in the use of storage.18

Further, the utilization study was based on aggregate data for the gas sales and19

transportation customer groups, respectively. Within the two groups, utilization was20

based on annual throughput. This assumes that all transportation customers use21



storage in precisely the same manner as the aggregate transportation group. This is1

highly unlikely.2

Q WHEN WOULD END-USE TRANSPORTATION CUSTOMERS USE STORAGE?3

A Storage is used when there is an imbalance between the amount of gas delivered to4

the customer and the amount of gas that the customer actually used for the same5

period. Thus, no storage would be used when a transportation customer’s gas6

deliveries are the same as its gas usage. This is the foundation for Consumers’7

proposed daily balancing provision.198

Q DOES CONSUMERS’ UTILIZATION STUDY DIRECTLY MEASURE THE9

IMBALANCES (THAT IS, THE VARIANCES BETWEEN GAS DELIVERIES AND10

GAS USAGE) FOR EACH EUT CUSTOMER?11

A No. The amount of gas injections and withdrawals for the entire transportation group12

does not reveal how individual EUT customers actually use storage. Further, only by13

coincidence would each EUT customer use storage during the same time period and14

in precisely the same magnitude. The diversity within the transportation group can15

be shown by comparing the Authorized Tolerance Levels (ATLs) of each16

transportation customer class. For example, more than 50% of the ATLs of XLT and17

XXLT customers are at 6.5% or lower. By contrast, over 80% of the ATLs of ST and18

LT customers are at 7.5%. This means that ST and LT customers have greater load19

imbalances and, thus, would use more storage relatively to their volumes than XLT20

and XXLT customers that manage their imbalances more closely. These differences21

are not specifically recognized in Consumers’ gas utilization study.22

19 Direct Testimony of Elizabeth A. Curtis at 6-8.



Q ARE THERE ANY RESTRICTIONS ON THE USE OF STORAGE THAT APPLY TO1

EUT CUSTOMERS?2

A Yes. Consumers’ Transportation Service Rate states:3

Monthly withdrawals from the customer's previous month-end balance4during November through March will be limited to the customer's5Contract Storage Quantity (CSQ), if any, plus 3% of the customer's6ACQ. If in any month the quantity of gas received by the Company,7less the allowance for gas-in-kind plus 3% of the transportation8customer's ACQ and its allowed CSQ is less than the quantity of gas9taken by the customer at the points of delivery, then the excess10delivery will be treated as unauthorized gas usage and subject to the11"Unauthorized Gas Usage Charge". For purposes of this calculation,12gas transferred to or from another customer during the billing month13shall not be considered.2014

Additionally:15

The monthly injection of gas into the customer's ATL and additional16CSQ, if any, shall be at the customer's discretion except in September17and October when any monthly injections in excess of the customer's18CSQ plus 1.43% of the customer's ACQ, will be charged the Load19Balancing Charge.2120

These tariff provisions clearly limit the use of storage by EUT customers during the21

critical injection and withdrawal periods. In general, no such limitations apply to gas22

sales customers. Clearly, EUT customers are not using storage in the same manner23

as gas sales customers.24

Q WHAT IS YOUR THIRD CONCERN WITH CONSUMERS’ ALLOCATION OF25

STORAGE COSTS?26

A The 50%/50% split between utilization and annual throughput does not appear to27

give proper emphasis on the importance of PDD demand in how Consumers plans28

20 M.P.S.C. No. 2 – Gas, Third Revised Sheet No. E-12.00 – Transportation Service Rate. (EffectiveAug. 7, 2017)

21 Id.



withdrawals from an array of storage facilities during the peak heating season. For1

example, in its 2017-2018 GCR filing, Consumers estimated that the amount of gas2

withdrawn from storage provided between 72% and 82% of the gas supplied on the3

peak days in January through March. In other words, storage is integral to4

maintaining reliable gas sales and delivery services on these critical days.5

Further, the 50%/50% split does not explicitly recognize the limitations6

imposed on transportation customers, as previously discussed7

Given the critical role that storage plays in maintaining reliability and the tariff8

limitations, I question whether a 50%/50% split is appropriate.9


A I understand that the methodology that Consumers is using to allocate storage-11

related costs has been approved by the Commission in recent cases. This fact12

notwithstanding, I recommend substituting PDD demand for peak month throughput13

in allocating the 50% of the storage costs that are considered peak-related for the14

same reasons that PDD demand should be used in applying the A&P method.15

I also recommend that Consumers conduct a specific study to evaluate the16

use of storage service for its EUT customers. This will require Consumers to collect17

data on daily gas deliveries and daily gas usage. The results of this study should be18

presented in Consumers’ next gas rate case.19

Q DID CONSUMERS PROVIDE SUCH A STUDY IN THIS CASE?20

A No. Consumers provided a “daily balancing” study that concluded that a21

transportation customer that balances gas nominations and gas deliveries on a daily22

basis would not utilize any storage. This study was generic in nature, and it does not23



specifically identify how any specific customers actually use storage. Determining a1

cost-based allocation and rate design of storage costs necessarily requires a more2

in-depth analysis of how individual transportation customers utilize storage.3

Revised Class Cost-of-Service Study

Q HAVE YOU CONDUCTED A REVISED CCOSS INCORPORATING YOUR4

SPECIFIC RECOMMENDATIONS?5

A Yes. My revised CCOSS is presented in Exhibit AB-4. It is based on Consumers’6

proposed revenue requirement for illustrative purposes only. Specifically, I replaced7

peak month throughput with PDD demand in allocating a portion of transmission,8

distribution and storage plant and related costs. I also allocated 25% of distribution9

mains as a customer-related cost based in part on the results of the Predominant10

Size method to more closely reflect cost-causation while providing only a modest11

recognition of the physical realities of a gas delivery system.12

The CCOSS results should be used to determine an appropriate allocation of13

any base revenue increase taking into account the allocation of the Residential14

Income Assistance (RIA) and Low Income Assistance (LIA) credits and applying rate15

stability adjustments (i.e., gradualism) as may be appropriate. This is demonstrated16

in Exhibit AB-5.17

Q PLEASE DESCRIBE EXHIBIT AB-5.18

A Exhibit AB-5 is a revised version of Consumers’ Exhibit No. A-16 (Schedule F-2.2)19

sponsored by Ms. Heather L Rayl. Page 1 shows the derivation of the rate design20

targets by customer class, while page 2 shows the allocation of the RIA/LIA credits.21



Referring to page 1, the allocated revenue requirement (line 1) reflects the1

revised CCOSS presented in Exhibit AB-4. The RIA/LIA credits (line 2) are spread2

to classes based on the revenue requirements derived from my revised CCOSS. I3

then set the revenue requirement for the gas sales (columns 2 through 5) and4

transportation groups (columns 6 through 9) to cost. Finally, I applied a gradualism5

adjustment with a 25% cap and a 0% floor on the increase (line 3). Thus, no6

customer class would experience either an extreme base rate increase or a rate7

decrease. Any revenue shortfall resulting from applying gradualism was retained8

within the two groups. The resulting class revenue allocation is summarized in the9

table below.10



Recommended Class Revenue AllocationBased on Consumers’ Proposed

Revenue Requirement

Rate GroupCustomer

Class

RevenueDeficiency

($000) Percent

Gas Sales

Residential $157,406 22.8%

Rate GS-1 $8,773 10.7%

Rate GS-2 $6,572 8.9%

Rate GS-3 $3,047 24.9%

Transportation

Rate ST $0 0.0%

Rate LT $0 0.0%

Rate XLT $1,864 8.3%

Rate XXLT $0 0.0%

Total $177,663 19.1%

Q HOW WOULD YOUR RECOMMENDED CLASS REVENUE ALLOCATION1

CHANGE IF THE COMMISSION AUTHORIZES A LOWER INCREASE THAN2

CONSUMERS IS PROPOSING?3

A My recommendation would be to scale down the revenue requirements derived from4

the revised CCOSS to determine the increases required by the gas sales and5

transportation rate groups in proportion to the change in the Company’s overall6

revenue requirements as authorized by the Commission. The resulting rate group7

revenue deficiencies should then be used to scale down the revenue deficiencies by8

customer class as shown in the above table.9


3. Transportation Rate Design


3. TRANSPORTATION RATE DESIGN

Q WHAT RATE DESIGN ISSUES ARE YOU ADDRESSING?1

A I address the design of the Transportation Service Rate.2

Q DO THE SAME PRINCIPLES USED IN A CLASS COST-OF-SERVICE STUDY3

ALSO APPLY TO RATE DESIGN?4

A Rate design is a continuation of the cost allocation process. Accordingly, a proper5

cost-based rate design should recognize the same cost-causative factors that are6

used in determining each class’s revenue requirement under a properly designed7

CCOSS.8

Q WHAT CHANGES IS CONSUMERS PROPOSING TO THE TRANSPORTATION9

SERVICE RATE?10

A Consumers is proposing a new service option, Rate XXLT, which would apply to11

customers who transport at least 4,000 MMcf per year. Rate XXLT would have a12

higher Master Customer Charge and a lower Transportation Rate than the other13

service options. Further, Rate XXLT customers would have the option to choose an14

ATL of 4% of the Annual Contract Quantity Tolerance Level.15

Q OTHER THAN SIZE ARE RATE XXLT CUSTOMERS DIFFERENT THAN XLT16

CUSTOMERS?17

A No. Consumers has identified two Rate XLT customers who would be eligible for18

Rate XXLT. These two customers currently have ATLs ranging from 6.5% to 8.5%.19

These are the same ATLs that are also characteristic of Rate XLT customers.2220

22 Exhibit No. A-16 (HLR-4), Schedule F-3, pages 9 (Rate XLT) and 10 (Rate XXLT).


3. Transportation Rate Design


Q SHOULD THE LOWER LOAD BALANCING CHARGE ONLY APPLY TO RATE1

XXLT CUSTOMERS?2

A No. The proposed 4% ATL should be available to all transportation customers, not3

just for customers eligible for Rate XXLT. A lower ATL would reward customers that4

more closely manage their supply imbalances (i.e., variations between gas5

nominations and gas deliveries), which in turn, reduces the amount of storage that is6

utilized. Thus, it would make sense to provide the same incentive to all7

transportation customers.8

Q WHY SHOULD CONSUMERS PROVIDE AN ADDITIONAL INCENTIVE FOR9

CUSTOMERS WHO ARE ABLE TO MORE CLOSELY MANAGE THEIR SUPPLY10

IMBALANCES?11

A This is consistent with a cost-based rate design, which sends price signals to12

encourage customers to properly manage their gas supply imbalances. Customers13

who can more effectively manage their gas supply imbalances use less storage and14

should pay a lower average rate than customers who are less able to manage them.15


A I recommend that the proposed 4% ATL option apply to all Transportation Service17

Rate customers.18


4. Conclusion


4. CONCLUSION

Q PLEASE SUMMARIZE YOUR RECOMMENDATIONS1

A The Commission should adopt the following recommendations:2

• Reject Consumers’ CCOSS.3

• Adopt a revised CCOSS, which makes two specific changes to4Consumers’ study:5

o Replace peak month throughput with Peak Day Demand.6

o Allocate 25% of distribution mains as a customer-related cost.7

• Order Consumers to conduct a more detailed study of how transportation8customers use storage and present the results of this study in its next rate9case.10

• Use the revised CCOSS to spread any revenue increase between the gas11sales and transportation rate groups, and apply gradualism to determine12the increases to specific rate classes within each group; specifically,13based on Consumers’ proposed increase, no rate class should receive an14increase higher than 25% and no rate class should receive a rate15decrease. The revenue requirements and required increases should be16scaled down if the Commission authorizes a lower increase than17Consumers is proposing.18

• Adopt Consumers’ proposed 4% ATL for Rate XXLT customers, but allow19the same option for Rate XLT customers.20


Appendix A


APPENDIX AQualifications of Jeffry Pollock


A Jeffry Pollock. My business mailing address is 12647 Olive Blvd., Suite 585, St.2

Louis, Missouri 63141.3


A I am an energy advisor and President of J. Pollock, Incorporated.5


A I have a Bachelor of Science Degree in Electrical Engineering and a Master’s7

Degree in Business Administration from Washington University. I have also8

completed a Utility Finance and Accounting course.9

Upon graduation in June 1975, I joined Drazen-Brubaker & Associates, Inc.10

(DBA). DBA was incorporated in 1972 assuming the utility rate and economic11

consulting activities of Drazen Associates, Inc., active since 1937. From April 199512

to November 2004, I was a managing principal at Brubaker & Associates (BAI).13

During my tenure at both DBA and BAI, I have been engaged in a wide range14

of consulting assignments including energy and regulatory matters in both the United15

States and several Canadian provinces. This includes preparing financial and16

economic studies of investor-owned, cooperative and municipal utilities on revenue17

requirements, cost of service and rate design, and conducting site evaluations.18

Recent engagements have included advising clients on electric restructuring issues,19

assisting clients to procure and manage electricity in both competitive and regulated20

markets, developing and issuing requests for proposals (RFPs), evaluating RFP21


Appendix A


responses and contract negotiation. I was also responsible for developing and1

presenting seminars on electricity issues.2

I have worked on various projects in over 20 states and several Canadian3

provinces, and have testified before the Federal Energy Regulatory Commission and4

the state regulatory commissions of Alabama, Arizona, Arkansas, Colorado,5

Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana,6

Michigan, Minnesota, Mississippi, Missouri, Montana, New Jersey, New Mexico, New7

York, Ohio, Pennsylvania, Texas, Virginia, Washington, and Wyoming. I have also8

appeared before the City of Austin Electric Utility Commission, the Board of Public9

Utilities of Kansas City, Kansas, the Board of Directors of the South Carolina Public10

Service Authority (a.k.a. Santee Cooper), the Bonneville Power Administration,11

Travis County (Texas) District Court, and the U.S. Federal District Court.12

Q PLEASE DESCRIBE J. POLLOCK, INCORPORATED.13

A J.Pollock assists clients to procure and manage energy in both regulated and14

competitive markets. The J.Pollock team also advises clients on energy and15

regulatory issues. Our clients include commercial, industrial and institutional energy16

consumers. J.Pollock is a registered Class I aggregator in the State of Texas.17

Appendix B

Testimony Filed in Regulatory Proceedings

by Jeffry Pollock

PROJECT UTILITY ON BEHALF OF DOCKET TYPE

REGULATORY

JURISDICTION SUBJECT DATE

160703 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 17-041 Direct AR Certificate of Convenience and

Necessity

2/23/2018

140404 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Indusrial Energy Consumers 47553 Direct TX Off-System Sales Margins; Renewable

Energy Credits

2/20/2018

140404 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Indusrial Energy Consumers 47461 2nd Supplemental Direct TX Certificate of Convenience and

Necessity

2/7/2018

140404 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Indusrial Energy Consumers 47461 Supplemental Direct TX Certificate of Convenience and

Necessity

1/4/2018

171003 CENTRAL HUDSON GAS & ELECTRIC Multiple Intervenors 17-E-0459/G-0460 Rebuttal NY Electric and Gas Embedded Class Cost

of Service; Class Revenue Allocation;

Gas Rate Design; Revenue Decoupling

Mechanism

12/18/2017

150504 SOUTHWESTERN PUBLIC SERVICE COMPANY Occidential Permian Ltd. 17-00044-UT Supplemental Direct NM Support of Unanimous Comprehensive

Stipulation

12/11/2017

140404 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Indusrial Energy Consumers 47461 Direct TX Certificate of Convenience and

Necessity

12/4/2017

171003 CENTRAL HUDSON GAS & ELECTRIC Multiple Intervenors 17-E-0459/G-0460 Direct NY Electric and Gas Embedded Class Cost

of Service; Class Revenue Allocation;

Customer Charges; Revenue

Decoupling Mechanism; Carbon

Program and EAM

11/21/2017

150504 SOUTHWESTERN PUBLIC SERVICE COMPANY Occidential Permian Ltd. 17-00044-UT Direct NM Certificate of Convenience and

Necessity

10/24/2017

140105 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Indusrial Energy Consumers 46936 Cross-Rebuttal TX Certificate of Convenience and

Necessity

10/23/2017

140105 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Indusrial Energy Consumers 46936 Supplemental Direct TX Certificate of Convenience and

Necessity

10/6/2017

170802 KENTUCKY POWER COMPANY Kentucky League of Cities 2017-00179 Direct KY Class Cost-of-Service Study; Class

Revenue Allocation

10/3/2017

140105 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Indusrial Energy Consumers 46936 Direct TX Certificate of Convenience and

Necessity

10/2/2017

170601 NIAGARA MOHAWK POWER CORP. Multiple Intervenors 17-E-0238 / 17-G-0239 Rebuttal NY Electric/Gas Embedded Class Cost of

Service; Class Revenue Allocation;

Electric/Gas Rate Design

9/15/2017

170401 CONSUMERS ENERGY COMPANY Association of Businesses Advocating Tariff

Equity

18322 Rebuttal MI Class Cost-of-Service Study, Rate

Design

9/7/2017

170801 PENNSYLVANIA-AMERICAN WATER COMPANY Pennsylvania-American Water Large Users

Group

R-2017-2595853 Rebuttal PA Rate Design 8/31/2017

170601 NIAGARA MOHAWK POWER CORP. Multiple Intervenors 17-E-0238 / 17-G-0239 Direct NY Electric/Gas Embedded Class Cost of

Service; Class Revenue Allocation;

Electric/Gas Rate Design, Electric/Gas

Rate Modifiers, AMI Cost Allocation

8/25/2017


Equity

18322 Direct MI Revenue Requirement, Class Cost-of-

Service Study, Rate Design

8/10/2017

140201 FLORIDA POWER & LIGHT COMPANY, DUKE ENERGY

FLORIDA, LLC, AND TAMPA ELECTRIC COMPANY

Florida Industrial Power Users Group 170057 Direct FL Fuel Hedging Practices 8/10/2017

140404 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 46449 Cross-Rebuttal TX Class Revenue Allocation and Rate

Design

5/19/2017

34

Appendix B


by Jeffry Pollock


REGULATORY


140404 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 46449 Direct TX Revenue Requirement, class cost of

service study, class revenue allocation

and rate design

4/25/2017

170101 KENTUCKY UTILITIES COMPANY Kentucky League of Cities 2016-00370 Supplemental Direct KY Class Cost-of-Service Study; Class

Revenue Allocation

4/14/2017

160702 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 46416 Direct TX Certificate of Convenience and

Necessity - Montgomery County Power

Station

3/31/2017

160402 SHARYLAND UTILITIES, L.P. Texas Industrial Energy Consumers 45414 Cross-Rebuttal TX Cost Allocation Issues; Class Revenue

Allocation

3/16/2017

150803 ENTERGY LOUISIANA, LLC Occidental Chemical Corporation U-34283 Direct* LA Approval to Construct Lake Charles

Power Station

3/13/2017

170102 LOUISVILLE GAS AND ELECTRIC COMPANY Louisville/Jefferson Metro Government 2016-00371 Direct KY Revenue Requirement Issues; Class

Cost-of-Service Study Electric/Gas;

Class Revenue Allocation Electric/Gas

3/3/2017

170101 KENTUCKY UTILITIES COMPANY Kentucky League of Cities 2016-00370 Direct KY Revenue Requirement Issues; Class

Cost-of-Service Study; Class Revenue

Allocation

3/3/2017

160402 SHARYLAND UTILITIES, L.P. Texas Industrial Energy Consumers 45414 Direct TX Class Cost-of-Service Study; Class

Revenue Allocation; Rate Design; TCRF

Allocation Factors; McAllen Division

Deferrals

2/28/2017

140105 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 46025 Direct TX Long-Term Purchased Power

Agreements

12/12/2016

151101 NORTHERN STATES POWER COMPANY Xcel Large Industrials 15-826 Surrebuttal MN Settlement, Cost-of-Service Study,

Class Revenue Allocation, Interruptible

Rates, Renew-A-Source

10/18/2016

151101 NORTHERN STATES POWER COMPANY Xcel Large Industrials 15-826 Rebutal MN Class Cost-of-Service Study, Class

Revenue Allocation

9/23/2016

131001 VICTORY ELECTRIC COOPERATION ASSOCIATION,

INC.

Westerrn Kansas Industrial Electric Consumers 16-VICE-494-TAR Surrebuttal KS Formula-Based Rate Plan 9/22/2016

160704 NATIONAL FUEL GAS DISTRIBUTION CORPORATION Multiple Intervenors 16-G-0257 Rebuttal NY Embedded Class Cost of Service; Class

Revenue Allocation; Rate Design

9/16/2016

140105 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 45524 Cross-Rebuttal TX Class Cost-of-Service Study; 9/7/2016

160301 METROPOLITAN EDISON COMPANY; PENNSYLVANIA

ELECTRIC COMPANY AND WEST PENN POWER

MEIUG, PICA and WPPII 2016-2537349

2016-2537352

2016-2537359

Surrebuttal PA Post-Test Year Sales Adjustment; Class


Allocation; Rate Design

8/31/2016

131001 VICTORY ELECTRIC COOPERATION ASSOCIATION,

INC.

Westerrn Kansas Industrial Electric Consumers 16-VICE-494-TAR Direct KS Formula-Based Rate Plan 8/30/2016

131001 WESTERN COOPERATIVE ELECTRIC ASSOCIATION,

INC.

Westerrn Kansas Industrial Electric Consumers 16-WSTE-496-TAR Direct KS Formula-Based Rate Plan and Debt

Service Payments

8/30/2016

160704 NATIONAL FUEL GAS DISTRIBUTION CORPORATION Multiple Intervenors 16-G-0257 Direct NY Embedded Class Cost of Service; Class


8/26/2016

35

Appendix B


by Jeffry Pollock


REGULATORY





2016-2537352

2016-2537359

Rebuttal PA Class Cost-of-Service; Class Revenue

Allocation

8/17/2016

140105 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 45524 Direct TX Revenue Requirement; Class Cost-of-

Service; Revenue Allocation; Rate

Design

8/16/2016




2016-2537352

2016-2537359

Direct PA Post-Test Year Sales Adjustment; Class



7/22/2016

160101 FLORIDA POWER & LIGHT COMPANY Florida Industrial Power Users Group 160021 DIrect FL Multi-Year Rate Plan, Construction

Work in Progress; Cost of Capital; Class

Revenue Allocation; Class Cost-of-

Service Study; Rate Design

7/7/2016

160103 CENTERPOINT ENERGY ARKANSAS GAS Arkansas Gas Consumers, Inc. 15-098-U Supplemental AR Support for Settlement Stipulation 7/1/2016

160503 MIDAMERICAN ENERGY COMPANY Tech Customers RPU-2016-0001 Direct IA Application of Advanced Ratemaking

Principles to Wind XI

6/21/2016

151101 NORTHERN STATES POWER COMPANY Xcel Large Industrials 15-826 Direct MN Class Cost-of-Service Study, Class

Revenue Allocation, Multi-Year Rate

Plan, Rate Design

6/14/2016

160103 CENTERPOINT ENERGY ARKANSAS GAS Arkansas Gas Consumers, Inc. 15-098-U Surrebuttal AR Incentive Compensation, Class Cost-of-

Service Study, Class Revenue

Allocation, LCS-1 Rate Design

6/7/2016

150504 SOUTHWESTERN PUBLIC SERVICE COMPANY Occidental Permian Ltd. 15-00296-UT Direct NM Support of Stipulation 5/13/2016

160102 CHEYENNE LIGHT, FUEL AND POWER COMPANY Dyno Nobel, Inc. and

HollyFrontier Cheyenne Refining LLC

20003-146-ET-15 Cross WY Large Power Contract Service Tariff 4/15/2016

160103 CENTERPOINT ENERGY ARKANSAS GAS Arkansas Gas Consumers, Inc. 15-098-U Direct AR Incentive Compensation, Class Cost-of-


Allocation, Act 725, Formula Rate Plan

4/14/2016

160102 CHEYENNE LIGHT, FUEL AND POWER COMPANY Dyno Nobel, Inc. and

HollyFrontier Cheyenne Refining LLC

20003-146-ET-15 Direct WY Large Power Contract Service Tariff 3/18/2016

36

Appendix B


by Jeffry Pollock


REGULATORY


150803 ENTERGY LOUISIANA, LLC, ENTERGY GULF STATES

LOUISIANA, L.L.C., AND ENTERGY LOUISIANA

POWER, LLC

Occidental Chemical Corporation U-33770 Cross-Answering LA Approval to Construct St. Charles

Power Station

2/26/2016

151102 NORTHERN INDIANA PUBLIC SERVICE COMPANY NLMK-Indiana 44688 Cross-Answering IN Cost-of-Service Study, Rider 775 2/16/2016

150803 ENTERGY LOUISIANA, LLC, ENTERGY GULF STATES

LOUISIANA, L.L.C., AND ENTERGY LOUISIANA

POWER, LLC

Occidental Chemical Corporation U-33770 Direct LA Approval to Construct St. Charles

Power Station

1/21/2016

150701 EL PASO ELECTRIC COMPANY Freeport-McMoRan Copper & Gold, Inc. 44941 Cross-Rebuttal TX Class Cost-of-Service Study, Class


1/15/2016

150503 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 15-015 Supplemental AR Support for Settlement Stipulation 12/31/2015

150701 EL PASO ELECTRIC COMPANY Freeport-McMoRan Copper & Gold, Inc. 44941 Direct TX Class Cost-of-Service Study, Class


12/11/2015

150503 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 15-015 Surrebuttal AR Post-Test-Year Additions; Class Cost-of-

Service Study; Class Revenue

Allocation; Rate Design; Riders;

Formula Rate Plan

11/24/2015

131001 MID-KANSAS ELECTRIC COMPANY, LLC, PRAIRIE

LAND ELECTRIC COOPERATIVE, INC., SOUTHERN

PIONEER ELECTRIC COMPANY, THE VICTORY

ELECTRIC COOPERATIVE ASSOCIATION, INC., AND

WESTERN COOPERATIVE ELECTRIC ASSOCIATION,

INC.

Western Kansas Industrial Electric Consumers 16-MKEE-023 Direct KS Formula Rate Plan for Distribution Utility 11/17/2015

130901 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 45084 Direct TX Transmission Cost Recovery Factor

Revenue Increase.

11/17/2015

140103 GEORGIA POWER COMPANY Georgia Industrial Group and Georgia

Assocation of Manufacturers

39638 Direct GA Natural Gas Price Assumptions, IFR

Mechanism, Seasonal FCR-24 Rates,

Imputed Capacity

11/4/2015

150801 NEW YORK STATE ELECTRIC & GAS CORPORATION

and ROCHESTER GAS AND ELECTRIC

CORPORATION

Multiple Intervenors 15-E-0283

15-G-0284

15-E-0285

15-G-0286

Rebuttal NY Electric and Gas Embedded Class Cost-

of-Service Studies, Class Revenue

Allocation

10/13/2015

150503 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 15-015 Direct AR Post-Test-Year Additions; Class Cost-of-


Allocation; Rate Design; Riders;

Formula Rate Plan

9/29/2015

150801 NEW YORK STATE ELECTRIC & GAS CORPORATION

and ROCHESTER GAS AND ELECTRIC

CORPORATION

Multiple Intervenors 15-E-0283

15-G-0284

15-E-0285

15-G-0286

Direct NY Electric and Gas Embedded Class Cost-

of-Service Studies, Class Revenue

Allocation, Electric Rate Design

9/15/2015

130602 SHARYLAND UTILITIES Texas Industrial Energy Consumers 44620 Cross-Rebuttal TX Transmission Cost Recovery Factor

Class Allocation Factors.

9/8/2015

150503 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 14-118 Surrebuttal AR Proposed Acquisition of Union Power

Station Power Block 2 and Cost

Recovery

8/21/2015

130602 SHARYLAND UTILITIES Texas Industrial Energy Consumers 44620 Direct TX Transmission Cost Recovery Factor

Class Allocation Factors

8/7/2015

37

Appendix B


by Jeffry Pollock


REGULATORY


150303 PECO ENERGY COMPANY Philadelphia Area Industrial Energy Users Group 2015-2468981 Surrebuttal PA Class Cost-of-Service, Capacity

Reservation Rider

8/4/2015

130701 WESTAR ENERGY INC. and

KANSAS GAS & ELECTRIC CO.

Occidental Chemical Corporation 15-WSEE-115-RTS Cross-Answering KS Class Cost-of-Service Study, Revenue

Allocation

7/22/2015

150303 PECO ENERGY COMPANY Philadelphia Area Industrial Energy Users Group 2015-2468981 Rebuttal PA Class Cost-of-Service, Class Revenue

Allocation, Rate Design, Capacity

Reservation Rider, Revenue Deoupling

7/21/2015

150504 SOUTHWEST ERN PUBLIC SERVICE COMPANY Occidental Periman Ltd. 15-00083 Direct NM Long-Term Purchased Power

Agreements

7/10/2015

150503 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 15-014 Surrebuttal AR Solar Power Purchase Agreement 7/10/2015



Occidental Chemical Corporation 15-WSEE-115-RTS Direct KS Class Cost-of-Service and Electric

Distrbution Grid Resiliency Program

7/9/2015

130901 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 43958 Supplemental

DIrect

TX Certificiate of Need for Union Power

Station Power Block 1

7/7/2015

150503 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 14-118 Direct AR Proposed Acquisition of Union Power

Station Power Block 2 and Cost

Recovery

7/2/2015

150303 PECO ENERGY COMPANY Philadelphia Area Industrial Energy Users Group 2015-2468981 Direct PA Class Cost-of-Service, Class Revenue

Allocation, Rate Design, Capacity

Reservation Rider

6/23/2015

150503 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 15-014-U Direct AR Solar Power Purchase Agreement 6/19/2015

140201 FLORIDA POWER & LIGHT COMPANY Florida Industrial Power Users Group 150075 Direct FL Cedar Bay Power Purchase Agreement 6/8/2015

140105 SOUTHWEST ERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 43695 Cross-Rebuttal TX Class Cost of Service Study; Class

Revenue Allocation

6/8/2015

140201 FLORIDA POWER AND LIGHT COMPANY, DUKE

ENERGY FLORIDA, GULF POWER COMPANY, TAMPA

ELECTRIC COMPANY

Florida Industrial Power Users Group 140226 Surrebuttal FL Opt-Out Provision 5/20/2015

140105 SOUTHWEST ERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 43695 Direct TX Post-Test Year Adjustments; Weather

Normalization

5/15/2015

140105 SOUTHWEST ERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 43695 Direct TX Class Cost of Service Study; Class

Revenue Allocation

5/15/2015

130901 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 43958 Direct TX Certificiate of Need for Union Power

Station Power Block 1

4/29/2015

140404 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 42370 Cross-Rebuttal TX Allocation and recovery of Municipal

Rate Case Expenses and the proposed

Rate-Case-Expense Surcharge Tariff.

1/27/2015

38

Appendix B


by Jeffry Pollock


REGULATORY


140904 WEST PENN POWER COMPANY West Penn Power Industrial Intervenors 2014-2428742 Surrebuttal PA Class Cost-of-Service Study; Class

Revenue Allocation; Large Commercial

and Industrial Rate Design; Storm

Damage Charge Rider

1/6/2015

140903 PENNSYLVANIA ELECTRIC COMPANY Penelec Industrial Customer Alliance 2014-2428743 Surrebuttal PA Class Cost-of-Service Study; Class



Damage Charge Rider

1/6/2015

140902 METROPOLITAN EDISON COMPANY Med-Ed Industrial Users Group 2014-2428745 Surrebuttal PA Class Cost-of-Service Study; Class



Damage Charge Rider

1/6/2015

140904 WEST PENN POWER COMPANY West Penn Power Industrial Intervenors 2014-2428742 Rebuttal PA Class Cost-of-Service Study; Class



Damage Charge Rider

12/18/2014

140903 PENNSYLVANIA ELECTRIC COMPANY Penelec Industrial Customer Alliance 2014-2428743 Rebuttal PA Class Cost-of-Service Study; Class



Damage Charge Rider

12/18/2014

140902 METROPOLITAN EDISON COMPANY Med-Ed Industrial Users Group 2014-2428745 Rebuttal PA Class Cost-of-Service Study; Class



Damage Charge Rider

12/18/2014

140804 PUBLIC SERVICE COMPANY OF COLORADO Colorado Healthcare Electric Coordinating

Council

14AL-0660E Cross CO Clean Air Clean Jobs Act Rider;

Transmission Cost Adjustment

12/17/2014

140904 WEST PENN POWER COMPANY West Penn Power Industrial Intervenors 2014-2428742 Direct PA Class Cost-of-Service Study; Class

Revenue Allocation, Rate Design,

Partial Services Rider; Storm Damage

Rider

11/24/2014

140903 PENNSYLVANIA ELECTRIC COMPANY Penelec Industrial Customer Alliance 2014-2428743 Direct PA Class Cost-of-Service Study; Class



Rider

11/24/2014

140902 METROPOLITAN EDISON COMPANY Med-Ed Industrial Users Group 2014-2428745 Direct PA Class Cost-of-Service Study; Class



Rider

11/24/2014

140905 CENTRAL HUDSON GAS & ELECTRIC Multiple Intervenors 14-E-0318 / 14-G-0319 Direct NY Class Cost-of-Service Study; Class

Revenue Allocation (Electric)

11/21/2014

140804 PUBLIC SERVICE COMPANY OF COLORADO Colorado Healthcare Electric Coordinating

Council

14AL-0660E Direct CO Clean Air Clean Jobs Act Rider; Electric

Commodity Adjustment Incentive

Mechanism

11/7/2014

140201 FLORIDA POWER AND LIGHT COMPANY Florida Industrial Power Users Group 140001-E Direct FL Cost-Effectiveness and Policy Issues

Surrounding the Investment in Working

Gas Production Facilities

9/22/2014

39

Appendix B


by Jeffry Pollock


REGULATORY


140401 ROCKY MOUNTAIN POWER Wyoming Industrial Energy Consumers 20000-446-ER14 Surrebuttal WY Class Cost-of-Service, Rule 12 (Line

Extension Policy)

9/19/2014

140805 INDIANA MICHIGAN POWER COMPANY I&M Industrial Group 44511 Direct IN Clean Energy Solar Pilot Project, Solar

Power Rider and Green Power Rider

9/17/2014

140401 ROCKY MOUNTAIN POWER Wyoming Industrial Energy Consumers 20000-446-ER14 Cross WY Class Cost-of-Service Study; Rule 12

Line Extension

9/5/2014

140201 VARIOUS UTILITIES Florida Industrial Power Users Group 140002-EI Direct FL Energy Efficiency Cost Recovery Opt-

Out Provision

9/5/2014

131002 NORTHERN STATES POWER COMPANY Xcel Large Industrials E-002/GR-13-868 Surrebuttal MN Nuclear Depreciation Expense,

Monticello EPU/LCM Project, Class

Cost-of-Service Study, Class Revenue

Allocation, Fuel Clause Rider Reform,

Rate Design

8/4/2014

140401 ROCKY MOUNTAIN POWER Wyoming Industrial Energy Consumers 20000-446-ER14 Direct WY Class Cost-of-Service Study, Rule 12

Line Extension

7/25/2014

140601 DUKE ENERGY FLORIDA NRG Florida, LP 140111 and 140110 Direct FL Cost-Effectiveness of Proposed Self

Build Generating Projects

7/14/2014

131002 NORTHERN STATES POWER COMPANY Xcel Large Industrials E-002/GR-13-868 Rebuttal MN Class Cost-of-Service Study, Class

Revenue Allocation

7/7/2014

140303 PPL ELECTRIC UTILITIES CORPORATION PP&L Industrial Customer Alliance 2013-2398440 Rebuttal PA Energy Efficiency Cost Recovery 7/1/2014

131002 NORTHERN STATES POWER COMPANY Xcel Large Industrials E-002/GR-13-868 Direct MN Revenue Requirements, Fuel Clause

Rider, Class Cost-of-Service Study,

Rate Design and Revenue Allocation

6/5/2014

140303 PPL ELECTRIC UTILITIES CORPORATION PP&L Industrial Customer Alliance 2013-2398440 Direct PA Energy Efficiency Cost Recovery 5/23/2014

140105 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 42042 Direct TX Transmission Cost Recovery Factor 4/24/2014

130901 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 41791 Cross TX Class Cost-of-Service Study and Rate

Design

1/31/2014

130901 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 41791 Direct TX Revenue Requirements, Fuel

Reconciliation; Cost Allocation Issues;

Rate Design Issues

1/10/2014

131005 DUQUESNE LIGHT COMPANY Duquesne Industrial Intervenors R-2013-2372129 Supplemental

Surrebuttal

PA Class Cost-of-Sevice Study 12/13/2013

131005 DUQUESNE LIGHT COMPANY Duquesne Industrial Intervenors R-2013-2372129 Surrebuttal PA Class Cost-of-Service Study; Cash

Working Capital; Miscellaneous General

Expense; Uncollectable Expense; Class

Revenue Allocation

12/9/2013

131005 DUQUESNE LIGHT COMPANY Duquesne Industrial Intervenors R-2013-2372129 Rebuttal PA Rate L Transmission Service; Class

Revenue Allocation

11/26/2013

40

Appendix B


by Jeffry Pollock


REGULATORY


130905 ENTERGY TEXAS, INC.

ITC HOLDINGS CORP.

Texas Industrial Energy Consumers 41850 Direct TX Rate Mitigation Plan; Conditions re

Transfer of Control of Ownership

11/6/2013

130602 SHARYLAND UTILITIES Texas Inustrial Energy Consumers and Atlas

Pipeline Mid-Continent WestTex, LLC

41474 Cross-Rebuttal TX Customer Class Definitions; Class

Revenue Allocation; Allocation of TTC

costs

11/4/2013

130501 MIDAMERICAN ENERGY COMPANY Deere & Company RPU-2013-0004 Surrebuttal IA Class Cost-of-Service Study; Class

Revenue Allocation; Depreciation

Surplus

11/4/2013

131005 DUQUESNE LIGHT COMPANY Duquesne Industrial Intervenors R-2013-2372129 Direct PA Class Cost-of-Service, Class Revenue

Allocations

11/1/2013

130906 PUBLIC SERVICE ENERGY AND GAS New Jersey Large Energy Users Coalition EO13020155 and

GO13020156

Direct NJ Energy Strong 10/28/2013

130903 GEORGIA POWER COMPANY Georgia Industrial Group and

Georgia Association of Manufacturers

36989 Direct GA Depreciation Expense, Alternate Rate

Plan, Return on Equity, Class Cost-of-


Allocation, Rate Design

10/18/2013

130602 SHARYLAND UTILITIES Texas Inustrial Energy Consumers and Atlas

Pipeline Mid-Continent WestTex, LLC

41474 Direct TX Regulatory Asset Cost Recovery; Class

Cost-of-Service Study, Class Revenue

Allocation, Rate Design

10/18/2013

130501 MIDAMERICAN ENERGY COMPANY Deere & Company RPU-2013-0004 Rebutal IA Class Cost-of-Service Study 10/1/2013

130902 FLORIDA POWER AND LIGHT COMPANY Florida Industrial Power Users Group 130007 Direct FL Environmental Cost Recovery Clause 9/13/2013

130501 MIDAMERICAN ENERGY COMPANY Deere & Company RPU-2013-0004 Direct IA Class Cost-of-Service Study, Class

Revenue Allocation, Depreciation, Cost

Recovery Clauses, Revenue Sharing,

Revenue True-up

9/10/2013

130202 SOUTHWESTERN PUBLIC SERVICE COMPANY Occidental Permian Ltd. 12-00350-UT Rebuttal NM RPS Cost Rider 9/9/2013



Occidental Chemical Corporation 13-WSEE-629-RTS Cross-Answering KS Cost Allocation Methodology 9/5/2013

130202 SOUTHWESTERN PUBLIC SERVICE COMPANY Occidental Permian Ltd. 12-00350-UT Direct NM Class Cost-of-Service Study 8/22/2013



Occidental Chemical Corporation 13-WSEE-629-RTS Direct KS Class Revenue Allocation. 8/21/2013

130203 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 41437 Direct TX Avoided Cost; Standby Rate Design 8/14/2013

100902 MID-KANSAS ELECTRIC COMPANY, LLC Western Kansas Industrial Electric Consumers 13-MKEE-699 Direct KS Class Revenue Allocation 8/12/2013

100902 MID-KANSAS ELECTRIC COMPANY, LLC Western Kansas Industrial Electric Consumers 13-MKEE-447 Supplemental KS Testimony in Support of Settlement 8/9/2013

100902 MID-KANSAS ELECTRIC COMPANY, LLC Western Kansas Industrial Electric Consumers 13-MKEE-447 Supplemental KS Modification Agreement 7/24/2013

130201 TAMPA ELECTRIC COMPANY Florida Industrial Power Users Group 130040 Direct FL GSD-IS Consolidation, GSD and IS

Rate Design, Class Cost-of-Service

Study, Planned Outage Expense, Storm

Damage Expense

7/15/2013

41

Appendix B


by Jeffry Pollock


REGULATORY


100902 MID-KANSAS ELECTRIC COMPANY, LLC Western Kansas Industrial Electric Consumers 13-MKEE-452 Supplemental KS Testimony in Support of Nonunanimous

Settlement

6/28/2013

121203 JERSEY CENTRAL POWER & LIGHT COMPANY Gerdau Ameristeel Sayreville, Inc. ER12111052 Direct NJ Cost of Service Study for GT-230 KV

Customers; AREP Rider

6/14/2013

100902 MID-KANSAS ELECTRIC COMPANY, LLC Western Kansas Industrial Electric Consumers 13-MKEE-447 Direct KS Wholesale Requirements Agreement;

Process for Excemption From

Regulation; Conditions Required for

Public Interest Finding on CCN spin-

down

5/14/2013

100902 MID-KANSAS ELECTRIC COMPANY, LLC Western Kansas Industrial Electric Consumers 13-MKEE-452 Cross KS Formula Rate Plan for Distribution Utility 5/10/2013

100902 MID-KANSAS ELECTRIC COMPANY, LLC Western Kansas Industrial Electric Consumers 13-MKEE-452 Direct KS Formula Rate Plan for Distribution Utility 5/3/2013

121001 ENTERGY TEXAS, INC.

ITC HOLDINGS CORP.

Texas Industrial Energy Consumers 41223 Direct TX Public Interest of Proposed Divestiture

of ETI's Transmission Business to an

ITC Holdings Subsidiary

4/30/2013

121101 NORTHERN STATES POWER COMPANY Xcel Large Industrials 12-961 Surrebuttal MN Depreciation; Used and Useful; Cost

Allocation; Revenue Allocation

4/12/2013

121101 NORTHERN STATES POWER COMPANY Xcel Large Industrials 12-961 Rebuttal MN Class Revenue Allocation. 3/25/2013

121101 NORTHERN STATES POWER COMPANY Xcel Large Industrials 12-961 Direct MN Depreciation; Used and Useful; Property

Tax; Cost Allocation; Revenue

Allocation; Competitive Rate & Property

Tax Riders

2/28/2013

91203 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 38951 Second Supplemental

Rebuttal

TX Competitive Generation Service Tariff 2/1/2013

91203 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 38951 Second Supplemental

Direct

TX Competitive Generation Service Tariff 1/11/2013

110202 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 40443 Cross Rebuttal TX Cost Allocation and Rate Design 1/10/2013

110202 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 40443 Direct TX Application of the Turk Plant Cost-Cap;

Revenue Requirements; Class Cost-of-


Allocation; Industrial Rate Design

12/10/2012

120301 FLORIDA POWER AND LIGHT COMPANY Florida Industrial Power Users Group 120015 Corrected Supplemental

Rebuttal

FL Support for Non-Unanimous Settlement 11/13/2012

120301 FLORIDA POWER AND LIGHT COMPANY Florida Industrial Power Users Group 120015 Corrected Supplemental

Direct

FL Support for Non-Unanimous Settlement 11/13/2012

120602 NIAGARA MOHAWK POWER CORP. Multiple Intervenors 12-E-0201/12-G-0202 Rebuttal NY Electric and Gas Class Cost-of-Service

Studies.

9/25/2012

120602 NIAGARA MOHAWK POWER CORP. Multiple Intervenors 12-E-0201/12-G-0202 Direct NY Electric and Gas Class Cost-of-Service

Study; Revenue Allocation; Rate

Design; Historic Demand

8/31/2012

100902 MID-KANSAS ELECTRIC COMPANY, LLC Western Kansas Industrial Electric Consumers 12-MKEE-650-TAR Direct KS Transmission Formula Rate Plan 7/31/2012



Occidental Chemical Corporation 12-WSEE-651-TAR Direct KS TDC Tariff 7/30/2012

120301 FLORIDA POWER AND LIGHT COMPANY Florida Industrial Power Users Group 120015 Direct FL Class Cost-of-Service Study, Revenue

Allocation, and Rate Design

7/2/2012

120101 LONE STAR TRANSMISSION, LLC Texas Industrial Energy Consumers 40020 Direct TX Revenue Requirement, Rider AVT 6/21/2012

42

Appendix B


by Jeffry Pollock


REGULATORY


111102 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 39896 Cross TX Class Cost-of-Service Study, Revenue

Allocation, and Rate Design

4/13/2012

111102 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 39896 Direct TX Revenue Requirements, Class Cost-of-

Service Study, Revenue Allocation, and

Rate Design

3/27/2012

91023 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 38951 Supplemental Rebuttal TX Competitive Generation Service Issues 2/24/2012

91203 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 38951 Supplemental Direct TX Competitive Generation Service Issues 2/10/2012

101101 AEP TEXAS CENTRAL COMPANY Texas Industrial Energy Consumers 39722 Direct TX Carrying Charge Rate Applicable to the

Additional True-Up Balance and Tax

Balances

11/4/2011

110703 GULF POWER COMPANY Florida Industrial Power Users Group 110138-EI Direct FL Cost Allocation and Storm Reserve 10/14/2011

90404 CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC Texas Industrial Energy Consumers 39504 Direct TX Carrying Charge Rate Applicable to the

Additional True-Up Balance and Taxes

9/12/2011

101101 AEP TEXAS NORTH COMPANY Texas Industrial Energy Consumers 39361 Cross-Rebuttal TX Energy Efficiency Cost Recovery Factor 8/10/2011

101101 AEP TEXAS CENTRAL COMPANY Texas Industrial Energy Consumers 39360 Cross-Rebuttal TX Energy Efficiency Cost Recovery Factor 8/10/2011

100503 ONCOR ELECTRIC DELIVERY COMPANY, LLC Texas Industrial Energy Consumers 39375 Direct TX Energy Efficiency Cost Recovery Factor 8/2/2011

90103 ALABAMA POWER COMPANY Alabama Industrial Energy Consumers 31653 Direct AL Renewable Purchased Power

Agreement

7/28/2011

101101 AEP TEXAS NORTH COMPANY Texas Industrial Energy Consumers 39361 Direct TX Energy Efficiency Cost Recovery Factor 7/26/2011

101101 AEP TEXAS CENTRAL COMPANY Texas Industrial Energy Consumers 36360 Direct TX Energy Efficiency Cost Recovery Factor 7/20/2011

90201 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 39366 Direct TX Energy Efficiency Cost Recovery Factor 7/19/2011

90404 CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC Texas Industrial Energy Consumers 39363 Direct TX Energy Efficiency Cost Recovery Factor 7/15/2011

101201 NORTHERN STATES POWER COMPANY Xcel Large Industrials E002/GR-10-971 Surrebuttal MN Depreciation; Non-Asset Margin

Sharing; Step-In Increase; Class Cost-of-



5/26/2011

101201 NORTHERN STATES POWER COMPANY Xcel Large Industrials E002/GR-10-971 Rebuttal MN Classification of Wind Investment 5/4/2011

101201 NORTHERN STATES POWER COMPANY Xcel Large Industrials E002/GR-10-971 Direct MN Surplus Depreciation Reserve, Incentive

Compensation, Non-Asset Trading

Margin Sharing, Cost Allocation, Class

Revenue Allocation, Rate Design

4/5/2011

101202 ROCKY MOUNTAIN POWER Wyoming Industrial Energy Consumers 20000-381-EA-10 Direct WY 2010 Protocols 2/11/2011

100802 TEXAS-NEW MEXICO POWER COMPANY Texas Industrial Energy Consumers 38480 Direct TX Cost Allocation, TCRF 11/8/2010

90402 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Traditional

Manufacturers Group

31958 Direct GA Alternate Rate Plan, Return on Equity,

Riders, Cost-of-Service Study, Revenue

Allocation, Economic Development

10/22/2010

90404 CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC Texas Industrial Energy Consumers 38339 Cross-Rebuttal TX Cost Allocation, Class Revenue

Allocation

9/24/2010

43

Appendix B


by Jeffry Pollock


REGULATORY


90404 CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC Texas Industrial Energy Consumers 38339 Direct TX Pension Expense, Surplus Depreciation

Reserve, Cost Allocation, Rate Design,

Riders

9/10/2010

100303 NIAGARA MOHAWK POWER CORP. Multiple Intervenors 10-E-0050 Rebuttal NY Multi-Year Rate Plan, Cost Allocation,

Revenue Allocation, Reconciliation

Mechanisms, Rate Design

8/6/2010

100303 NIAGARA MOHAWK POWER CORP. Multiple Intervenors 10-E-0050 Direct NY Multi-Year Rate Plan, Cost Allocation,

Revenue Allocation, Reconciliation

Mechanisms, Rate Design

7/14/2010

91203 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 37744 Cross Rebuttal TX Cost Allocation, Revenue Allocation,

CGS Rate Design, Interruptible Service

6/30/2010

91203 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 37744 Direct TX Class Cost of Service Study, Revenue

Allocation, Rate Design, Competitive

Generation Services, Line Extension

Policy

6/9/2010

90201 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 37482 Cross Rebuttal TX Allocation of Purchased Power Capacity

Costs

2/3/2010


Manufacturers Group

28945 Direct GA Fuel Cost Recovery 1/29/2010

90201 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 37482 Direct TX Purchased Power Capacity Cost Factor 1/22/2010

90403 VIRGINIA ELECTRIC AND POWER COMPANY MeadWestvaco Corporation PUE-2009-00081 Direct VA Allocation of DSM Costs 1/13/2010

90201 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 37580 Direct TX Fuel refund 12/4/2009

90403 VIRGINIA ELECTRIC AND POWER COMPANY MeadWestvaco Corporation PUE-2009-00019 Direct VA Standby rate design; dynamic pricing 11/9/2009

90403 VIRGINIA ELECTRIC AND POWER COMPANY MWV PUE-2009-00019 Direct VA Base Rate Case 11/9/2009

80601 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 37135 Direct TX Transmission cost recovery factor 10/22/2009

80703 MID-KANSAS ELECTRIC COMPANY, LLC Western Kansas Industrial Electric Consumers 09-MKEE-969-RTS Direct KS Revenue requirements, TIER, rate

design

10/19/2009

90601 VARIOUS UTILITIES Florida Industrial Power Users Group 090002-EG Direct FL Interruptible Credits 10/2/2009

80505 ONCOR ELECTRIC DELIVERY COMPANY Texas Industrial Energy Consumers 36958 Cross Rebuttal TX 2010 Energy efficiency cost recovery

factor

8/18/2009

81001 PROGRESS ENERGY FLORIDA Florida Industrial Power Users Group 90079 Direct FL Cost-of-service study, revenue

allocation, rate design, depreciation

expense, capital structure

8/10/2009

90404 CENTERPOINT Texas Industrial Energy Consumers 36918 Cross Rebuttal TX Allocation of System Restoration Costs 7/17/2009

90301 FLORIDA POWER AND LIGHT COMPANY Florida Industrial Power Users Group 080677 Direct FL Depreciation; class revenue allocation;

rate design; cost allocation; and capital

structure

7/16/2009

90201 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 36956 Direct TX Approval to revise energy efficiency

cost recovery factor

7/16/2009

90601 VARIOUS UTILITIES Florida Industrial Power Users Group VARIOUS DOCKETS Direct FL Conservation goals 7/6/2009

90201 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 36931 Direct TX System restoration costs under Senate

Bill 769

6/30/2009

90502 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 36966 Direct TX Authority to revise fixed fuel factors 6/18/2009

80805 TEXAS-NEW MEXICO POWER COMPANY Texas Industrial Energy Consumers 36025 Cross-Rebuttal TX Cost allocatiion, revenue allocation and

rate design

6/10/2009

44

Appendix B


by Jeffry Pollock


REGULATORY


81201 NORTHERN STATES POWER COMPANY Xcel Large Industrials 08-1065 Surrebuttal MN Cost allocation, revenue allocation, rate

design

5/27/2009

80805 TEXAS-NEW MEXICO POWER COMPANY Texas Industrial Energy Consumers 36025 Direct TX Cost allocation, revenue allocation, rate

design

5/27/2009

90403 VIRGINIA ELECTRIC AND POWER COMPANY MeadWestvaco Corporation PUE-2009-00018 Direct VA Transmission cost allocation and rate

design

5/20/2009

90101 NORTHERN INDIANA PUBLIC SERVICE COMPANY Beta Steel Corporation 43526 Direct IN Cost allocation and rate design 5/8/2009

81203 ENTERGY SERVICES, INC Texas Industrial Energy Consumers ER008-1056 Rebuttal FERC Rough Production Cost Equalization

payments

5/7/2009

81201 NORTHERN STATES POWER COMPANY Xcel Large Industrials 08-1065 Rebuttal MN Class revenue allocation and the

classification of renewable energy costs

5/5/2009

81201 NORTHERN STATES POWER COMPANY Xcel Large Industrials 08-1065 Direct MN Cost-of-service study, class revenue

allocation, and rate design

4/7/2009

81203 ENTERGY SERVICES, INC Texas Industrial Energy Consumers ER08-1056 Answer FERC Rough Production Cost Equalization

payments

3/6/2009

80901 ROCKY MOUNTAIN POWER Wyoming Industrial Energy Consumers 20000-333-ER-08 Direct WY Cost of service study; revenue

allocation; inverted rates; revenue

requirements

1/30/2009

81203 ENTERGY SERVICES Texas Industrial Energy Consumers ER08-1056 Direct FERC Entergy's proposal seeking Commission

approval to allocate Rough Production

Cost Equalization payments

1/9/2009

80505 ONCOR ELECTRIC DELIVERY COMPANY &

TEXAS ENERGY FUTURE HOLDINGS LTD

Texas Industrial Energy Consumers 35717 Cross Rebuttal TX Retail transformation; cost allocation,

demand ratchet waivers, transmission

cost allocation factor

12/24/2008

70101 GEORGIA POWER COMPANY Georgia Industrial Group and Georgia Traditional

Manufacturers Association

27800 Direct GA Cash Return on CWIP associated with

the Plant Vogtle Expansion

12/19/2008

80802 TAMPA ELECTRIC COMPANY The Florida Industrial Power Users Group and

Mosaic Company

080317-EI Direct FL Revenue Requirements, retail class

cost of service study, class revenue

allocation, firm and non firm rate design

and the Transmission Base Rate

Adjustment

11/26/2008



Texas Industrial Energy Consumers 35717 Direct TX Revenue Requirement, class cost of

service study, class revenue allocation

and rate design

11/26/2008

80601 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 35763 Supplemental Direct TX Recovery of Energy Efficiency Costs 11/6/2008

80601 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 35763 Cross-Rebuttal TX Cost Allocation, Demand Ratchet,

Renewable Energy Certificates (REC)

10/28/2008

80601 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 35763 Direct TX Revenue Requirements, Fuel

Reconciliation Revenue Allocation, Cost-

of-Service and Rate Design Issues

10/13/2008

50106 ALABAMA POWER COMPANY Alabama Industrial Energy Consumers 18148 Direct AL Energy Cost Recovery Rate

(WITHDRAWN)

9/16/2008

50701 ENTERGY TEXAS, INC. Texas Industrial Energy Consumers 35269 Direct TX Allocation of rough production costs

equalization payments

7/9/2008

70703 ENTERGY GULF STATES UTILITIES, TEXAS Texas Industrial Energy Consumers 34800 Direct TX Non-Unanimous Stipulation 6/11/2008

50103 TEXAS PUC STAFF Texas Industrial Energy Consumers 33672 Supplemental Rebuttal TX Transmission Optimization and Ancillary

Services Studies

6/3/2008

50103 TEXAS PUC STAFF Texas Industrial Energy Consumers 33672 Supplemental Direct TX Transmission Optimization and Ancillary

Services Studies

5/23/2008

45

Appendix B


by Jeffry Pollock


REGULATORY


60104 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 33891 Supplemental Cross

Rebuttal

TX Certificate of Convenience and

Necessity

5/21/2008

60104 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 33891 Supplemental Direct TX Certificate of Convenience and

Necessity

5/8/2008

70703 ENTERGY GULF STATES UTILITES, TEXAS Texas Industrial Energy Consumers 34800 Cross-Rebuttal TX Cost Allocation and Rate Design and

Competitive Generation Service

4/18/2008


Manufacturers Group

26794 Direct GA Fuel Cost Recovery 4/15/2008

41229 TEXAS-NEW MEXICO POWER COMPANY Texas Industrial Energy Consumers 35038 Rebuttal TX Over $5 Billion Compliance Filing 4/14/2008

70703 ENTERGY GULF STATES UTILITES, TEXAS Texas Industrial Energy Consumers 34800 Direct TX Eligible Fuel Expense 4/11/2008

70703 ENTERGY GULF STATES UTILITES, TEXAS Texas Industrial Energy Consumers 34800 Direct TX Competitive Generation Service Tariff 4/11/2008

70703 ENTERGY GULF STATES UTILITES, TEXAS Texas Industrial Energy Consumers 34800 Direct TX Revenue Requirements 4/11/2008

70703 ENTERGY GULF STATES UTILITES, TEXAS Texas Industrial Energy Consumers 34800 Direct TX Cost of Service study, revenue

allocation, design of firm, interruptible

and standby service tariffs;

interconnection costs

4/11/2008

71202 SOUTHWESTERN PUBLIC SERVICE COMPANY Occidental Periman Ltd. 07-00319-UT Rebuttal NM Revenue requirements, cost of service

study, rate design

3/28/2008

61101 AEP TEXAS CENTRAL COMPANY Texas Industrial Energy Consumers 35105 Direct TX Over $5 Billion Compliance Filing 3/24/2008

51101 CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC Texas Industrial Energy Consumers 32902 Direct TX Over $5 Billion Compliance Filing 3/20/2008

71202 SOUTHWESTERN PUBLIC SERVICE COMPANY Occidental Periman Ltd. 07-00319-UT Direct NM Revenue requirements, cost of service

study (COS); rate design

3/7/2008

50701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers 34724 Direct TX IPCR Rider increase and interim

surcharge

11/28/2007


Manufacturers Group

25060-U Direct GA Return on equity; cost of service study;

revenue allocation; ILR Rider; spinning

reserve tariff; RTP

10/24/2007



Texas Industrial Energy Consumers 34077 Direct TX Acquisition; public interest 9/14/2007

60104 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 33891 Direct TX Certificate of Convenience and

Necessity

8/30/2007

61201 ALTAMAHA ELECTRIC MEMBERSHIP CORPORATION SP Newsprint Company 25226-U Rebuttal GA Discriminatory Pricing; Service

Territorial Transfer

7/17/2007

61201 ALTAMAHA ELECTRIC MEMBERSHIP CORPORATION SP Newsprint Company 25226-U Direct GA Discriminatory Pricing; Service

Territorial Transfer

7/6/2007

70502 PROGRESS ENERGY FLORIDA Florida Industrial Power Users Group 070052-EI Direct FL Nuclear uprate cost recovery 6/19/2007

60601 TEXAS PUC STAFF Texas Industrial Energy Consumers 32795 Rebuttal Remand TX Interest rate on stranded cost

reconciliation

6/15/2007

70603 ELECTRIC TRANSMISSION TEXAS LLC Texas Industrial Energy Consumers 33734 Direct TX Certificate of Convenience and

Necessity

6/8/2007

60601 TEXAS PUC STAFF Texas Industrial Energy Consumers 32795 Remand TX Interest rate on stranded cost

reconciliation

6/8/2007

50103 TEXAS PUC STAFF Texas Industrial Energy Consumers 33672 Rebuttal TX CREZ Nominations 5/21/2007

50701 ENTERGY GULF STATES UTILITES, TEXAS Texas Industrial Energy Consumers 33687 Direct TX Transition to Competition 4/27/2007

50103 TEXAS PUC STAFF Texas Industrial Energy Consumers 33672 Direct TX CREZ Nominations 4/24/2007

61101 AEP TEXAS CENTRAL COMPANY Texas Industrial Energy Consumers 33309 Cross-Rebuttal TX Cost Allocation,Rate Design, Riders 4/3/2007

50701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers 32710 Cross-Rebuttal TX Fuel and Rider IPCR Reconcilation 3/16/2007

61101 AEP TEXAS NORTH COMPANY Texas Industrial Energy Consumers 33310 Direct TX Cost Allocation,Rate Design, Riders 3/13/2007

46

Appendix B


by Jeffry Pollock


REGULATORY


61101 AEP TEXAS CENTRAL COMPANY Texas Industrial Energy Consumers 33309 Direct TX Cost Allocation,Rate Design, Riders 3/13/2007

50701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers 32710 Direct TX Fuel and Rider IPCR Reconcilation 2/28/2007

41219 AEP TEXAS NORTH COMPANY Texas Industrial Energy Consumers 31461 Direct TX Rider CTC design 2/15/2007

50701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers 33586 Cross-Rebuttal TX Hurricane Rita reconstruction costs 1/30/200760104 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 32898 Direct TX Fuel Reconciliation 1/29/2007

50701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers 33586 Direct TX Hurricane Rita reconstruction costs 1/18/200760303 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Textile

Manufacturers Group

23540-U Direct GA Fuel Cost Recovery 1/11/2007

60503 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 32766 Cross Rebuttal TX Cost allocation, Cost of service, Rate

design

1/8/2007

60503 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 32766 Direct TX Cost allocation, Cost of service, Rate

design

12/22/2006

60503 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 32766 Direct TX Revenue Requirements, 12/15/2006

60503 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 32766 Direct TX Fuel Reconcilation 12/15/2006

50701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers 32907 Cross Rebuttal TX Hurricane Rita reconstruction costs 10/12/0650701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers 32907 Direct TX Hurricane Rita reconstruction costs 10/09/0660101 COLQUITT EMC ERCO Worldwide 23549-U Direct GA Service Territory Transfer 09/13/06

60601 TEXAS PUC STAFF Texas Industrial Energy Consumers 32795 Cross Rebuttal TX Stranded Cost Reallocation 09/07/06

50503 AEP TEXAS CENTRAL COMPANY Texas Industrial Energy Consumers 32758 Direct TX Rider CTC design and cost recovery 08/24/0660601 TEXAS PUC STAFF Texas Industrial Energy Consumers 32795 Direct TX Stranded Cost Reallocation 08/23/06

60104 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 32672 Direct TX ME-SPP Transfer of Certificate to

SWEPCO

8/23/2006

60503 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 32685 Direct TX Fuel Surcharge 07/26/06

60301 PUBLIC SERVICE ELECTRIC AND GAS COMPANY New Jersey Large Energy Consumers 171406 Direct NJ Gas Delivery Cost allocation and Rate

design

06/21/06

60303 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Textile

Manufacturers Group

22403-U Direct GA Fuel Cost Recovery Allowance 05/05/06

50503 AEP TEXAS CENTRAL COMPANY Texas Industrial Energy Consumers 32475 Cross-Rebuttal TX ADFIT Benefit 04/27/06

50503 AEP TEXAS CENTRAL COMPANY Texas Industrial Energy Consumers 32475 Direct TX ADFIT Benefit 04/17/06

41229 TEXAS-NEW MEXICO POWER COMPANY Texas Industrial Energy Consumers 31994 Cross-Rebuttal TX Stranded Costs and Other True-Up

Balances

3/16/2006

41229 TEXAS-NEW MEXICO POWER COMPANY Texas Industrial Energy Consumers 31994 Direct TX Stranded Costs and Other True-Up

Balances

3/10/2006

50303 SOUTHWESTERN PUBLIC SERVICE COMPANY Occidental Periman Ltd.

Occidental Power Marketing

05-00341 Direct NM Fuel Reconciliation 3/7/2006

50701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers

31544

Cross-Rebuttal TX Transition to Competition Costs 01/13/06

50701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers

31544

Direct TX Transition to Competition Costs 01/13/06

50601 PUBLIC SERVICE ELECTRIC AND GAS COMPANY

AND EXELON CORPORATION

New Jersey Large Energy Consumers

Retail Energy Supply Association

BPU EM05020106

OAL PUC-1874-05

Surrebuttal NJ Merger 12/22/2005



EL05-19-002;

ER05-168-001

Responsive FERC Fuel Cost adjustment clause (FCAC) 11/18/2005

50601 PUBLIC SERVICE ELECTRIC AND GAS COMPANY

AND EXELON CORPORATION

New Jersey Large Energy Consumers

Retail Energy Supply Association

BPU EM05020106

OAL PUC-1874-05

Direct NJ Merger 11/14/2005

50102 PUBLIC UTILITY COMMISSION OF TEXAS Texas Industrial Energy Consumers 31540 Direct TX Nodal Market Protocols 11/10/2005

50701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers 31315 Cross-Rebuttal TX Recovery of Purchased Power Capacity

Costs

10/4/2005

47

Appendix B


by Jeffry Pollock


REGULATORY


50701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers 31315 Direct TX Recovery of Purchased Power Capacity

Costs

9/22/2005



EL05-19-002;

ER05-168-001

Responsive FERC Fuel Cost Adjustment Clause (FCAC) 9/19/2005

50503 AEP TEXAS CENTRAL COMPANY Texas Industrial Energy Consumers 31056 Direct TX Stranded Costs and Other True-Up

Balances

9/2/2005



EL05-19-00;

ER05-168-00

Direct FERC Fuel Cost adjustment clause (FCAC) 8/19/2005


Manufacturers Group


41230 CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC Texas Industrial Energy Consumers 30706 Direct TX Competition Transition Charge 3/16/2005

41230 CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC Texas Industrial Energy Consumers 30485 Supplemental Direct TX Financing Order 1/14/2005

41230 CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC Texas Industrial Energy Consumers 30485 Direct TX Financing Order 1/7/2005

8201 PUBLIC SERVICE COMPANY OF COLORADO Colorado Energy Consumers 04S-164E Cross Answer CO Cost of Service Study, Interruptible Rate

Design

12/13/2004

8201 PUBLIC SERVICE COMPANY OF COLORADO Colorado Energy Consumers 04S-164E Answer CO Cost of Service Study, Interruptible Rate

Design

10/12/2004


Manufacturers Group

18300-U Direct GA Revenue Requirements, Revenue

Allocation, Cost of Service, Rate

Design, Economic Development

10/8/2004

8195 CENTERPOINT, RELIANT AND TEXAS GENCO Texas Industrial Energy Consumers 29526 Direct TX True-Up 6/1/2004

8156 GEORGIA POWER COMPANY/SAVANNAH ELECTRIC

AND POWER COMPANY

Georgia Industrial Group 17687-U/17688-U Direct GA Demand Side Management 5/14/2004

8148 TEXAS-NEW MEXICO POWER COMPANY Texas Industrial Energy Consumers 29206 Direct TX True-Up 3/29/2004

8095 CONECTIV POWER DELIVERY New Jersey Large Energy Consumers ER03020110 Surrebuttal NJ Cost of Service 3/18/2004

8111 AEP TEXAS CENTRAL COMPANY Texas Industrial Energy Consumers 28840 Rebuttal TX Cost Allocation and Rate Design 2/4/2004

8095 CONECTIV POWER DELIVERY New Jersey Large Energy Consumers ER03020110 Direct NJ Cost Allocation and Rate Design 1/4/2004

7850 RELIANT ENERGY HL&P Texas Industrial Energy Consumers 26195 Supplemental Direct TX Fuel Reconciliation 9/23/2003

8045 VIRGINIA ELECTRIC AND POWER COMPANY Virginia Committee for Fair Utility Rates PUE-2003-00285 Direct VA Stranded Cost 9/5/2003


Manufacturers Group


8002 AEP TEXAS CENTRAL COMPANY Flint Hills Resources, LP 25395 Direct TX Delivery Service Tariff Issues 5/9/2003

7857 PUBLIC SERVICE ELECTRIC AND GAS COMPANY New Jersey Large Energy Consumers ER02050303 Supplemental NJ Cost of Service 3/14/2003

7850 RELIANT ENERGY HL&P Texas Industrial Energy Consumers 26195 Direct TX Fuel Reconciliation 12/31/2002

7857 PUBLIC SERVICE ELECTRIC AND GAS COMPANY New Jersey Large Energy Consumers ER02050303 Surrebuttal NJ Revenue Allocation 12/16/2002

7836 PUBLIC SERVICE COMPANY OF COLORADO Colorado Energy Consumers 02S-315EG Answer CO Incentive Cost Adjustment 11/22/2002

7857 PUBLIC SERVICE ELECTRIC AND GAS COMPANY New Jersey Large Energy Consumers ER02050303 Direct NJ Revenue Allocation 10/22/2002

7863 DOMINION VIRGINIA POWER Virginia Committee for Fair Utility Rates PUE-2001-00306 Direct VA Generation Market Prices 8/12/2002

7718 FLORIDA POWER CORPORATION Florida Industrial Power Users Group 000824-EI Direct FL Rate Design 1/18/2002


Manufacturers Group

14000-U Direct GA Cost of Service Study, Revenue

Allocation,

Rate Design

10/12/2001

7555 TAMPA ELECTRIC COMPANY Florida Industrial Power Users Group 010001-EI Direct FL Rate Design 10/12/2001

7658 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 24468 Direct TX Delay of Retail Competition 9/24/2001

7647 ENTERGY GULF STATES, INC. Texas Industrial Energy Consumers 24469 Direct TX Delay of Retail Competition 9/22/2001

7608 RELIANT ENERGY HL&P Texas Industrial Energy Consumers 23950 Direct TX Price to Beat 7/3/2001

48

Appendix B


by Jeffry Pollock


REGULATORY



Manufacturers Group


7520 GEORGIA POWER COMPANY

SAVANNAH ELECTRIC & POWER COMPANY

Georgia Industrial Group/Georgia Textile

Manufacturers Group

12499-U,13305-U,

13306-U

Direct GA Integrated Resource Planning 5/11/2001

7303 ENTERGY GULF STATES, INC. Texas Industrial Energy Consumers 22356 Rebuttal TX Allocation/Collection of Municipal

Franchise Fees

3/31/2001

7309 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 22351 Cross-Rebuttal TX Energy Efficiency Costs 2/22/2001

7305 CPL, SWEPCO, and WTU Texas Industrial Energy Consumers 22352, 22353, 22354 Cross-Rebuttal TX Allocation/Collection of Municipal

Franchise Fees

2/20/2001


Manufacturers Group

13140-U Direct GA Interruptible Rate Design 2/16/2001

7305 CPL, SWEPCO, and WTU Texas Industrial Energy Consumers 22352, 22353, 22354 Supplemental Direct TX Transmission Cost Recovery Factor 2/13/2001

7310 TEXAS-NEW MEXICO POWER COMPANY Texas Industrial Energy Consumers 22349 Cross-Rebuttal TX Rate Design 2/12/2001

7308 TXU ELECTRIC COMPANY Texas Industrial Energy Consumers 22350 Cross-Rebuttal TX Unbundled Cost of Service 2/12/2001

7303 ENTERGY GULF STATES, INC. Texas Industrial Energy Consumers 22356 Cross-Rebuttal TX Stranded Cost Allocation 2/6/2001

7308 TXU ELECTRIC COMPANY Texas Industrial Energy Consumers 22350 Direct TX Rate Design 2/5/2001

7303 ENTERGY GULF STATES, INC. Texas Industrial Energy Consumers 22356 Supplemental Direct TX Rate Design 1/25/2001

7307 RELIANT ENERGY HL&P Texas Industrial Energy Consumers 22355 Cross-Rebuttal TX Stranded Cost Allocation 1/12/2001

7303 ENTERGY GULF STATES, INC. Texas Industrial Energy Consumers 22356 Direct TX Stranded Cost Allocation 1/9/2001

7307 RELIANT ENERGY HL&P Texas Industrial Energy Consumers 22355 Direct TX Cost Allocation 12/13/2000

7375 CENTRAL POWER AND LIGHT COMPANY Texas Industrial Energy Consumers 22352 Cross-Rebuttal TX CTC Rate Design 12/1/2000

7375 CENTRAL POWER AND LIGHT COMPANY Texas Industrial Energy Consumers 22352 Direct TX Cost Allocation 11/1/2000

7308 TXU ELECTRIC COMPANY Texas Industrial Energy Consumers 22350 Direct TX Cost Allocation 11/1/2000

7308 TXU ELECTRIC COMPANY Texas Industrial Energy Consumers 22350 Cross-Rebuttal TX Cost Allocation 11/1/2000

7305 CPL, SWEPCO, and WTU Texas Industrial Energy Consumers 22352, 22353, 22354 Direct TX Excess Cost Over Market 11/1/2000

7315 VARIOUS UTILITIES Texas Industrial Energy Consumers 22344 Direct TX Generic Customer Classes 10/14/2000

7308 TXU ELECTRIC COMPANY Texas Industrial Energy Consumers 22350 Direct TX Excess Cost Over Market 10/10/2000

7315 VARIOUS UTILITIES Texas Industrial Energy Consumers 22344 Rebuttal TX Excess Cost Over Market 10/1/2000

7310 TEXAS-NEW MEXICO POWER COMPANY Texas Industrial Energy Consumers 22349 Cross-Rebuttal TX Generic Customer Classes 10/1/2000

7310 TEXAS-NEW MEXICO POWER COMPANY Texas Industrial Energy Consumers 22349 Direct TX Excess Cost Over Market 9/27/2000

7307 RELIANT ENERGY HL&P Texas Industrial Energy Consumers 22355 Cross-Rebuttal TX Excess Cost Over Market 9/26/2000

7307 RELIANT ENERGY HL&P Texas Industrial Energy Consumers 22355 Direct TX Excess Cost Over Market 9/19/2000


Manufacturers Group

11708-U Rebuttal GA RTP Petition 3/24/2000


Manufacturers Group

11708-U Direct GA RTP Petition 3/1/2000

7232 PUBLIC SERVICE COMPANY OF COLORADO Colorado Industrial Energy Consumers 99A-377EG Answer CO Merger 12/1/1999

7258 TXU ELECTRIC COMPANY Texas Industrial Energy Consumers 21527 Direct TX Securitization 11/24/1999

7246 CENTRAL POWER AND LIGHT COMPANY Texas Industrial Energy Consumers 21528 Direct TX Securitization 11/24/1999

7089 VIRGINIA ELECTRIC AND POWER COMPANY Virginia Committee for Fair Utility Rates PUE980813 Direct VA Unbundled Rates 7/1/1999

7090 AMERICAN ELECTRIC POWER SERVICE

CORPORATION

Old Dominion Committee for Fair Utility Rates PUE980814 Direct VA Unbundled Rates 5/21/1999

7142 SHARYLAND UTILITIES, L.P. Sharyland Utilities 20292 Rebuttal TX Certificate of Convenience and

Necessity

4/30/1999

49

Appendix B


by Jeffry Pollock


REGULATORY


7060 PUBLIC SERVICE COMPANY OF COLORADO Colorado Industrial Energy Consumers Group 98A-511E Direct CO Allocation of Pollution Control Costs 3/1/19997039 SAVANNAH ELECTRIC AND POWER COMPANY Various Industrial Customers 10205-U Direct GA Fuel Costs 1/1/1999

6945 TAMPA ELECTRIC COMPANY Florida Industrial Power Users Group 950379-EI Direct FL Revenue Requirement 10/1/1998

6873 GEORGIA POWER COMPANY Georgia Industrial Group 9355-U Direct GA Revenue Requirement 10/1/1998

6729 VIRGINIA ELECTRIC AND POWER COMPANY Virginia Committee for Fair Utility Rates PUE960036,PUE960296 Direct VA Alternative Regulatory Plan 8/1/19986713 CENTRAL POWER AND LIGHT COMPANY Texas Industrial Energy Consumers 16995 Cross-Rebuttal TX IRR 1/1/1998

6758 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 17460 Direct TX Fuel Reconciliation 12/1/1997

6729 VIRGINIA ELECTRIC AND POWER COMPANY Virginia Committee for Fair Utility Rates PUE960036,PUE960296 Direct VA Alternative Regulatory Plan 12/1/19976713 CENTRAL POWER AND LIGHT COMPANY Texas Industrial Energy Consumers 16995 Direct TX Rate Design 12/1/1997

6646 ENTERGY TEXAS Texas Industrial Energy Consumers 16705 Rebuttal TX Competitive Issues 10/1/1997

6646 ENTERGY TEXAS Texas Industrial Energy Consumers 16705 Rebuttal TX Competition 10/1/1997

6646 ENTERGY TEXAS Texas Industrial Energy Consumers 473-96-2285/16705 Direct TX Rate Design 9/1/1997

6646 ENTERGY TEXAS Texas Industrial Energy Consumers 16705 Direct TX Wholesale Sales 8/1/1997

6744 TAMPA ELECTRIC COMPANY Florida Industrial Power Users Group 970171-EU Direct FL Interruptible Rate Design 5/1/1997

6632 MISSISSIPPI POWER COMPANY Colonial Pipeline Company 96-UN-390 Direct MS Interruptible Rates 2/1/1997

6558 TEXAS-NEW MEXICO POWER COMPANY Texas Industrial Energy Consumers 15560 Direct TX Competition 11/11/1996

6508 TEXAS UTILITIES ELECTRIC COMPANY Texas Industrial Energy Consumers 15195 Direct TX Treatment of margins 9/1/1996

6475 TEXAS UTILITIES ELECTRIC COMPANY Texas Industrial Energy Consumers 15015 DIRECT TX Real Time Pricing Rates 8/8/1996

6449 CENTRAL POWER AND LIGHT COMPANY Texas Industrial Energy Consumers 14965 Direct TX Quantification 7/1/1996

6449 CENTRAL POWER AND LIGHT COMPANY Texas Industrial Energy Consumers 14965 Direct TX Interruptible Rates 5/1/1996

6449 CENTRAL POWER AND LIGHT COMPANY Texas Industrial Energy Consumers 14965 Rebuttal TX Interruptible Rates 5/1/1996

6523 PUBLIC SERVICE COMPANY OF COLORADO Multiple Intervenors 95A-531EG Answer CO Merger 4/1/1996

6235 TEXAS UTILITIES ELECTRIC COMPANY Texas Industrial Energy Consumers 13575 Direct TX Competitive Issues 4/1/1996

6435 SOUTHWESTERN PUBLIC SERVICE COMMISSION Texas Industrial Energy Consumers 14499 Direct TX Acquisition 11/1/1995

6391 HOUSTON LIGHTING & POWER COMPANY Grace, W.R. & Company 13988 Rebuttal TX Rate Design 8/1/1995

6353 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 14174 Direct TX Costing of Off-System Sales 8/1/1995

6157 WEST TEXAS UTILITIES COMPANY Texas Industrial Energy Consumers 13369 Rebuttal TX Cancellation Term 8/1/1995

6391 HOUSTON LIGHTING & POWER COMPANY Grace, W.R. & Company 13988 Direct TX Rate Design 7/1/1995

6157 WEST TEXAS UTILITIES COMPANY Texas Industrial Energy Consumers 13369 Direct TX Cancellation Term 7/1/1995

6296 GEORGIA POWER COMPANY Georgia Industrial Group 5601-U Rebuttal GA EPACT Rate-Making Standards 5/1/1995

6296 GEORGIA POWER COMPANY Georgia Industrial Group 5601-U Direct GA EPACT Rate-Making Standards 5/1/1995

6278 COMMONWEALTH OF VIRGINIA VCFUR/ODCFUR PUE940067 Rebuttal VA Integrated Resource Planning 5/1/1995

6295 GEORGIA POWER COMPANY Georgia Industrial Group 5600-U Supplemental GA Cost of Service 4/1/19956063 PUBLIC SERVICE COMPANY OF COLORADO Multiple Intervenors 94I-430EG Rebuttal CO Cost of Service 4/1/1995

6063 PUBLIC SERVICE COMPANY OF COLORADO Multiple Intervenors 94I-430EG Reply CO DSM Rider 4/1/1995

6295 GEORGIA POWER COMPANY Georgia Industrial Group 5600-U Direct GA Interruptible Rate Design 3/1/1995

6278 COMMONWEALTH OF VIRGINIA VCFUR/ODCFUR PUE940067 Direct VA EPACT Rate-Making Standards 3/1/1995

6125 SOUTHWESTERN PUBLIC SERVICE COMPANY Texas Industrial Energy Consumers 13456 Direct TX DSM Rider 3/1/1995

6235 TEXAS UTILITIES ELECTRIC COMPANY Texas Industrial Energy Consumers 13575|13749 Direct TX Cost of Service 2/1/1995

6063 PUBLIC SERVICE COMPANY OF COLORADO Multiple Intervenors 94I-430EG Answering CO Competition 2/1/1995

50

Appendix B


by Jeffry Pollock


REGULATORY


6061 HOUSTON LIGHTING & POWER COMPANY Texas Industrial Energy Consumers 12065 Direct TX Rate Design 1/1/1995

6181 GULF STATES UTILITIES COMPANY Texas Industrial Energy Consumers 12852 Direct TX Competitive Alignment Proposal 11/1/1994

6061 HOUSTON LIGHTING & POWER COMPANY Texas Industrial Energy Consumers 12065 Direct TX Rate Design 11/1/1994

5929 CENTRAL POWER AND LIGHT COMPANY Texas Industrial Energy Consumers 12820 Direct TX Rate Design 10/1/1994

6107 SOUTHWESTERN ELECTRIC POWER COMPANY Texas Industrial Energy Consumers 12855 Direct TX Fuel Reconciliation 8/1/1994

6112 HOUSTON LIGHTING & POWER COMPANY Texas Industrial Energy Consumers 12957 Direct TX Standby Rates 7/1/1994

5698 GULF POWER COMPANY Misc. Group 931044-EI Direct FL Standby Rates 7/1/1994

5698 GULF POWER COMPANY Misc. Group 931044-EI Rebuttal FL Competition 7/1/1994

6043 EL PASO ELECTRIC COMPANY Phelps Dodge Corporation 12700 Direct TX Revenue Requirement 6/1/1994

6082 GEORGIA PUBLIC SERVICE COMMISSION Georgia Industrial Group 4822-U Direct GA Avoided Costs 5/1/1994

6075 GEORGIA POWER COMPANY Georgia Industrial Group 4895-U Direct GA FPC Certification Filing 4/1/1994

6025 MISSISSIPPI POWER & LIGHT COMPANY MIEG 93-UA-0301 Comments MS Environmental Cost Recovery Clause 1/21/19945971 FLORIDA POWER & LIGHT COMPANY Florida Industrial Power Users Group 940042-EI Direct FL Section 712 Standards of 1992 EPACT 1/1/1994

*Testimony was subsequently removed from the official record by Ruling dated March 30, 2017

51


Appendix C


APPENDIX CProcedure for Conducting a Class Cost-of-Service Study

Q WHAT PROCEDURES ARE USED IN A CLASS COST-OF-SERVICE STUDY?1

A The basic procedure for conducting a class cost-of-service study (CCOSS) is fairly2

simple. First, we identify the different types of costs (functionalization), determine3

their primary causative factors (classification), and then apportion each item of cost4

among the various service classes (allocation). Adding up the individual pieces5

gives the total cost for each class.6

Identifying the utility’s different levels of operation is a process referred to as7

functionalization. The utility’s investments and expenses are separated into8

production, transmission, distribution, and other functions. To a large extent, this is9

done in accordance with the Uniform System of Accounts developed by the FERC.10

Once costs have been functionalized, the next step is to identify the primary11

causative factor (or factors). This step is referred to as classification. Costs are12

classified as demand-related, energy- (or commodity-) related or customer-related.13

Demand (or capacity) related costs vary with peak demand, which is measured in14

kilowatts or peak day send out. This includes production, transmission, and some15

distribution investment and related fixed operation and maintenance (O&M)16

expenses. As explained later, peak demand determines the amount of capacity17

needed for reliable service. Energy-related costs vary with natural gas throughput,18

which is measured in dekatherms. Energy-related costs include purchased gas and19

variable O&M expense. Customer-related costs vary directly with the number of20

customers and include expenses such as a portion of distribution mains, meters,21

service drops, billing, and customer service.22


Appendix C


Each functionalized and classified cost must then be allocated to the various1

customer classes. This is accomplished by developing allocation factors that reflect2

the percentage of the total cost that should be paid by each class. The allocation3

factors should reflect cost-causation; that is, the degree to which each class caused4

the utility to incur the cost.5

Further, each customer class should be comprised of customers having6

similar characteristics. The relevant characteristics include the type of end-use7

customer (e.g., residential, general service sales, transportation), average size and8

load factor. Allocating costs to homogeneous customer classes will ensure that the9

rates derived from a class cost-of-service study are just and reasonable and reflect10

the actual cost to serve.11

Q WHAT KEY PRINCIPLES ARE RECOGNIZED IN A CLASS COST-OF-SERVICE12

STUDY FOR NATURAL GAS DELIVERY SERVICE?13

A A properly conducted Gas CCOSS recognizes two key cost-causation principles.14

First, not all gas customers purchase gas supplied by a local distribution company15

(LDC). Some customers purchase and transport their own gas to the city gate.16

Thus, the LDC does not incur purchased gas and other related costs to serve a17

transportation customer. Second, since cost causation is also related to how natural18

gas is used, both the timing and rate of gas consumption (i.e., demand) are critical.19

Consistent with the obligation to serve and to ensure reliability, the LDC must20

purchase sufficient gas supply to meet the maximum needs of its sales customers.21

The LDC must also construct the required distribution mains and other facilities to22

attach customers to the system, and these facilities must be sized to meet the23


Appendix C


expected contribution to the Peak Day Design, which is the maximum expected1

demand on the delivery system.2


In the matter of the application ofConsumers Energy Company forauthority to increase its rates forthe distribution of natural gas andfor other relief.

§§§§§

Case No. U-18424

Direct Testimony and Exhibits

of

BILLIE S. LACONTE

On Behalf of

Association of Businesses Advocating Tariff Equity

February 28, 2018

Billie S. LaConteDirectPage i



In the matter of the application ofConsumers Energy Company forauthority to increase its rates forthe distribution of natural gas andother relief.

§§§§§

Case No. U-18424

Table of Contents

LIST OF SCHEDULES.......................................................................................................... ii

GLOSSARY OF ACRONYMS .............................................................................................. iii

1. INTRODUCTION, QUALIFICATIONS AND SUMMARY.................................................. 1

Summary.....................................................................................................................2

2. FAIR RATE OF RETURN................................................................................................ 4

3. EVALUATION OF CONSUMERS’ ROE .......................................................................... 6

Risk Reducing Enhancements.....................................................................................9

Flotation Costs ..........................................................................................................13

Proxy Group..............................................................................................................15

Capital Asset Pricing Model.......................................................................................21

Risk Premium Method ...............................................................................................27

Discounted Cash Flow Method..................................................................................32

Comparable Earnings Method...................................................................................35

Summary...................................................................................................................36

4. CAPITAL STRUCTURE .................................................................................................39

5. CONCLUSION ...............................................................................................................42

APPENDIX A.......................................................................................................................43

APPENDIX B.......................................................................................................................45

Billie S. LaConteDirectPage ii


LIST OF SCHEDULES

Exhibit Description

AB-6 RRA Regulatory Focus Major Rate Case Decisions 2017

AB-7 Recommended ROE and Rate of Return

AB-8 Cost per Customer Due to Overstated ROE

AB-9 Capital Asset Pricing Model

AB-10 Corrected Risk Premium Analysis

AB-11 Risk Premium Analysis

AB-12 Discounted Cash Flow Model

AB-13 Comparable Earnings Analysis

AB-14 Recommended Capital Structure

Billie S. LaConteDirectPage iii


GLOSSARY OF ACRONYMS

Term Definition

ABATE Association of Businesses Advocating Tariff Equity

ALJ Administrative Law Judge

CAPM Capital Asset Pricing Model

Company orConsumers

Consumers Energy Company

DCF Discounted Cash Flow

ECAPM Empirical Capital Asset Pricing Model

EPS Earnings Per Share

IBES Institutional Brokers' Estimate System

IG` Investment Grade

IRM Investment Recovery Mechanism

LDC Local Distribution Company

MRP Market Risk Premium

PFD Proposal for Decision

RDM Revenue Decoupling Mechanism

ROE Return on Equity

RRA Regulatory Research Associates

S&P Standard and Poor’s

Value Line Value Line Investment Survey

Billie S. LaConteDirectPage 1



Direct Testimony of Billie S. LaConte

1. INTRODUCTION, QUALIFICATIONS AND SUMMARY


A Billie S. LaConte, 12647 Olive Blvd., Suite 585, St. Louis, MO 63141.2


A I am an energy advisor and Associate Consultant at J. Pollock, Incorporated.4


A I have a Bachelor of Arts Degree in Mathematics from Boston University and a6

Master’s Degree in Business Administration from Washington University. Since7

graduation in 1995, I have been engaged in a variety of consulting assignments,8

including energy procurement and regulatory matters in both the United States and9

several Canadian provinces. My qualifications are documented in Appendix A. A list10

of my appearances is provided in Appendix B to this testimony.11

Q ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?12

A I am appearing on behalf of the Association of Businesses Advocating Tariff Equity13

(ABATE), a group of businesses including many of Michigan’s largest employers that14

are large energy customers of Consumers Energy Company (Consumers or15

Company). ABATE members are large gas consumers that transport their gas16

supplies through Consumers under the rates, terms and conditions of Consumers’17

Transportation Service Rate.18




Q WHAT IS THE PURPOSE OF YOUR TESTIMONY?1

A I address Consumers’ requested return on equity (ROE). In addition, I address the2

Company’s capital structure.3

Q ARE YOU SPONSORING ANY EXHIBITS WITH YOUR TESTIMONY?4

A Yes. I am sponsoring Exhibits AB-6 through AB-14. These exhibits were prepared5

by me or under my supervision and direction.6

Q ARE YOU ACCEPTING CONSUMERS’ POSITIONS ON THE ISSUES NOT7

ADDRESSED IN YOUR DIRECT TESTIMONY?8

A No. One should not interpret the fact that I do not address every issue raised by9

Consumers as an endorsement of its proposals.10

Summary11

Q PLEASE SUMMARIZE YOUR FINDINGS AND RECOMMENDATIONS.12

A My findings and recommendations are as follows:13

• The 10.5% ROE recommended by Consumers’ ROE witness, Mr.14Maddipati, is based on an improper application of accepted methods15(i.e., Capital Asset Pricing Model (CAPM), Discounted Cash Flow16Model (DCF), and Risk Premium). Mr. Maddipati also relies on the17Comparable Earnings method, which does not provide a reliable18estimate of the cost of equity.19

• Correcting these application errors would reduce Consumers’20recommended ROE by between 38 and 174 basis points. This would21reduce Consumers’ proposed revenue requirement by between $14.122million and $64.2 million.23

• An inflated ROE will harm customers and only serve to benefit24Consumers’ shareholders. The average authorized ROE for a natural25gas utility in 2017 was 9.72%, almost 80 basis points below Consumers’26




recommended ROE of 10.5%.1 If the Commission approves1Consumers’ recommended ROE it would result in customers over-2paying the Company by $28.9 million, as compared to the national3average ROE.4

• The Company fails to recognize all of the regulatory enhancements that5mitigate its financial and business risks, such as the Revenue6Decoupling Mechanism (RDM) and the Investment Recovery7Mechanism (IRM). Together, these mechanisms significantly reduce8its variability in income, which in turn lowers Consumers’ overall risk.9

• Consumers includes a flotation cost adjustment, which is improper and10unnecessary. Excluding the flotation cost adjustment would lower the11revenue requirement by $5.3 million.12

• Consumers’ proxy group includes companies that are riskier than the13Company because they are not classified as natural gas utilities. Mr.14Maddipati includes companies that are classified by Value Line15Investment Services (Value Line) or Standard and Poor’s (S&P) as16either electric companies or natural gas-diversified companies. Most17do not generate the majority of their operating revenues from gas18operations. These companies are riskier than a regulated, natural gas19distribution company and should not be used to determine the return20on equity for Consumers Energy’s gas utility.21

• The appropriate capital structure for Consumers is 48.21% debt and2251.49% equity with 0.29% preferred equity. The lower equity ratio23reduces Consumers’ revenue requirement by $4.8 million. This24represents a fair mix of debt and equity and will allow Consumers to25fund its investment needs. It also follows the Commission’s directive to26further reduce Consumers’ permanent equity ratio to 50%.27

Q HOW IS YOUR TESTIMONY ORGANIZED?28

A My testimony comprises three sections:29

• The determination of a fair rate of return;30

• An evaluation of Consumers’ ROE analysis; and31

• The recommended capital structure.32

1 Regulatory Research Associates, an Offering of S&P Global Market Intelligence, RRA RegulatoryFocus, Major Rate Case Decisions 2017


2. Fair Rate of Return


2. FAIR RATE OF RETURN

Q WHAT ARE THE NECESSARY GUIDELINES ESTABLISHED BY THE U.S.1

SUPREME COURT TO DETERMINE A FAIR RATE OF RETURN ON EQUITY FOR2

A REGULATED MONOPOLY?3

A The U.S. Supreme Court determined the principles that should be used to determine4

a fair return on capital for regulated monopolies. In Bluefield Water Works &5

Improvement Co. v. the Public Service Commission of West Virginia (Bluefield) the6

Supreme Court recognized that utilities compete with other firms in the market for7

investor capital and should have the opportunity to earn a fair return on capital. The8

Court stated:9

A public utility is entitled to such rates as will permit it to earn a return10on the value of the property which it employs for the convenience of the11public equal to that generally being made at the same time and in the12same general part of the country on investments in other business13undertakings which are attended by corresponding risks and14uncertainties; but it has no constitutional right to profits such as are15realized or anticipated in highly profitable enterprises or speculative16ventures. The return should be reasonably sufficient to assure17confidence in the financial soundness of the utility and should be18adequate, under efficient and economical management, to maintain19and support its credit and enable it to raise the money necessary for20the proper discharge of its public duties.221

22In the case of the Federal Power Commission v. Hope Natural Gas Company (Hope)23

the Supreme Court explained that:24

The rate-making process under the [Natural Gas] Act, i.e., the fixing of25‘just and reasonable’ rates, involves a balancing of the investor and the26consumer interests….From the investor or company point of view it is27important that there be enough revenue not only for operating28expenses but also for the capital costs of the business. These include29

2 Bluefield Waterworks & Improvement Co. v. Public Service Commission of West Virginia et al., 43S. Ct. 675, 67 L.Ed. 1176, P.U.R. 1923D 11 (1923).


2. Fair Rate of Return


service on the debt and dividends on the stock. By that standard the1return to the equity owner should be commensurate with returns on2investments in other enterprises having corresponding risks. That3return, moreover, should be sufficient to assure confidence in the4financial integrity of the enterprise, so as to maintain its credit and to5attract capital.36

Q DOES CONSUMERS’ RECOMMENDED ROE MEET THESE REQUIREMENTS?7

A No, Consumers’ recommended ROE does not appropriately balance the interests of8

investors and customers, as required by Hope. The Company’s requested ROE is too9

high and heavily favors investors. I discuss this in more detail later in my testimony.10

Furthermore, the Company’s recommended ROE is not based on investments in other11

business undertakings which are attended by corresponding risks and uncertainties12

as determined in Bluefield. This is also discussed this in more detail later in my13

testimony. Therefore, Consumers’ recommended ROE does not meet the14

requirements as determined by the U.S. Supreme Court and should be rejected.15

3 Federal Power Commission et al. v. Hope Natural Gas Co. City of Cleveland, 64 S. Ct. 281, 88L.Ed. 333, 51 P.U.R.(NS) 193 (1944).


3. Evaluation of Consumers’ ROE


3. EVALUATION OF CONSUMERS’ ROE

Q WHAT RETURN ON EQUITY IS CONSUMERS REQUESTING?1

A Consumers is requesting a 10.5% ROE.42

Q HAVE YOU REVIEWED THE BASIS FOR CONSUMERS’ PROPOSED 10.5% ROE?3

A Yes. I have reviewed Consumers’ testimony and analysis. The estimated ROE of4

10.5% is too high primarily because it relies on assumptions that are unrealistic and5

includes an unnecessary adjustment, such as the flotation cost adjustment.6

Q WHAT METHODS DID CONSUMERS USE TO SUPPORT ITS RECOMMENDED7

10.5% ROE?8

A The Company based its recommendation on nine separate variations of three9

standard methodologies—DCF, CAPM, and Risk Premium—and one methodology10

that is seldom used to quantify ROE (i.e., Comparable Earnings). As discussed later,11

the erroneous application of these methods result in inflated ROEs and in one instance12

the overstatement is a result of a calculation error. In addition, the Company includes13

a flotation cost adjustment that unnecessarily inflates its ROE and the resulting14

revenue deficiency.15

Q ARE THERE ANY OTHER FACTORS THAT CONTRIBUTED TO CONSUMERS’16

INFLATED ROE REQUEST?17

A Yes, as I will address in more detail later, Consumers included several incompatible18

companies in its proxy group. In determining the appropriate ROE for a utility’s gas19

operations, it is necessary to use a proxy group made up of companies that also derive20

4 Direct Testimony of Srikanth Maddipati at 5.




the majority of their revenues from gas operations. Consumers’ proxy group includes1

companies that derive a majority of their operating revenues from electric operations2

and other unrelated services. These companies are riskier than a local distribution3

company (LDC), like Consumers’ gas operations, and should not be included in the4

proxy group.5

Q ARE YOU ABLE TO QUANTIFY THE IMPACT THAT CONSUMERS’ INFLATED6

ROE ESTIMATES HAVE ON THE COMPANY’S TEST YEAR REVENUE7

REQUIREMENT?8

A The revenue impact of Consumers’ inflated ROE is substantial, and is summarized in9

Table 1 below.10

Table 1Impact of Consumers’ Proposed ROEs5

MethodologyConsumers’Proposed6 Corrected

RevenueImpact

($Millions)CAPM 10.88% 8.76% $78.2

ECAPM 11.27% N/A N/A

Risk Premium 13.17% 9.41% $138.6

DCF 9.86% 8.84% $37.7

Comparable Earnings 11.08% 10.12% $35.5

National Average7 10.50% 9.72% $28.9

11

As the table demonstrates, correcting Consumers’ inflated ROEs would reduce12

Consumers’ revenue deficiency by between $28.9 million and $138.6 million.13

5 The revenue impacts reflect the corporate income tax rate of 35%.


7 The National Average compares Consumers’ recommended ROE and the National Averageauthorized ROE for 2017.




Eliminating only the flotation cost adjustment of 14 basis points would reduce the1

revenue deficiency by $5.3 million.2

Q WHAT IS THE NATIONAL AVERAGE ROE FOR NATURAL GAS UTILITIES?3

A As stated above, the national average authorized ROE for gas utilities in 2017 was4

9.72%.8 This is based on the average authorized ROE for 24 gas utilities. See Exhibit5

AB-6 which is a report from Regulatory Research Reports that provides an overview6

of authorized ROEs for electric and gas utilities in 2017.7

Q HOW WOULD CONSUMERS’ PROJECTED REVENUE DEFICIENCY BE8

AFFECTED IF THE COMMISSION SET CONSUMERS’ ROE AT THE NATIONAL9

AVERAGE?10

A Consumers’ projected revenue deficiency would decrease by $28.9 million if its11

authorized ROE was lowered to 9.72%. The details of this calculation are shown in12

Exhibit AB-7.13

Q DO YOU HAVE ANY OTHER COMMENTS REGARDING CONSUMERS’14

REQUESTED ROE?15

A Yes. Consumers’ requested 10.5% ROE is too high, harms ratepayers and only16

serves to reward its shareholders. An ROE this high will have a negative economic17

impact on the ratepayers.18

8 See supra note 1.




Q PLEASE EXPLAIN.1

A Consumers’ requested ROE of 10.5% is grossly overstated. The ROE for a regulated2

company should be fair to not only the company, but to its ratepayers, as well. An3

ROE that is overstated will harm ratepayers because customers will wind up paying4

more than is necessary for the utility to remain competitive and attract capital. As5

explained in the Hope decision, “the fixing of ‘just and reasonable’ rates, involves a6

balancing of the investor and the consumer interests.”9 The ROE that Consumers is7

requesting is not just and reasonable and will produce windfall profits for the8

Company’s investors. As shown above, if the Company is awarded a 10.5% ROE,9

compared to the national average of 9.72%, investors will receive a windfall profit of10

$28.9 million, at the ratepayers’ expense.11

Q WHAT IS THE EFFECT OF AN OVERSTATED ROE ON RATEPAYERS?12

A Compared to the national average ROE of 9.72%, the higher ROE would cost a typical13

residential customer about $12.33 per customer per year as shown on Exhibit AB-8.14

If the Commission approves Consumers’ requested increase, a typical residential15

customer using 93 Mcf per year may see an increase of approximately $42 per year.1016

The higher ROE represents 29% of the $42 increase.17

Risk Reducing Enhancements

Q HOW DO YOU DEFINE RISK?18

A Risk represents variability in income. To the extent such variability is small or has19

been reduced by other means, the risk to the Company is lower than before.20

9 See supra note 2.

10 Application at Proposed Notice of Hearing.




Q DOES CONSUMERS CURRENTLY HAVE ANY TOOLS AVAILABLE THAT ALLOW1

IT TO REDUCE ITS RISK?2

A Yes, the utility has separate cost recovery clauses, including the Gas RDM, which3

essentially insures recovery of its fixed costs, and the IRM, which currently allows for4

the recovery of incremental capital investment of five transmission and distribution5

programs for 2018 and 2019.116

Q HOW DOES THE USE OF A REVENUE DECOUPLING MECHANISM REDUCE7

CONSUMERS’ RISK?8

A A RDM promotes stable cash flow. Rates are adjusted periodically to insure that the9

Company does not over-collect or under-collect its fixed costs. This promotes revenue10

stability and leads to lower financial risk for the Company. As noted by the Maryland11

Public Service Commission: “"[Decoupling] will provide insurance that Pepco will12

achieve its level of revenue approved in this case. Thus, Pepco is less risky with the13

BSA [Bill Stabilization Adjustment] than without it. In response to this decline in risk,14

all parties recognize the appropriateness of reducing Pepco’s return on equity by some15

amount.”1216

Q HOW DOES THE USE OF AN INVESTMENT RECOVERY MECHANISM REDUCE17

CONSUMERS’ RISK?18

A The investment recovery mechanism reduces the Company’s risk because it allows19

the utility to collect costs on incremental capital investment in between rate cases.20

This, too, reduces the Company’s variability in income, which further reduces its risk.21

11 Direct Testimony of Michael A. Torrey at 27-28.

12 Potomac Electric Power Company, 258 P.U.R.4th 463 (Md.P.S.C. 2007), (emphasis added)




Q HAS THE COMMISSION RECOGNIZED THAT THESE TOOLS REDUCE THE1

COMPANY’S RISK?2

A Yes. In Order U-18124, the Commission stated: “[T]he Commission agrees with the3

ALJ that the IRM and RDM approved in this order reduce the company’s risk.”134

Q HOW DOES THIS LOWER RISK AFFECT THE COMPANYS’ ROE?5

A The lower risk emphasizes the reasonableness of a lower ROE for the utility. The6

RDM and IRM lower the Company’s variability in income. The risk that the Company7

was exposed to, i.e. that the forecast revenues and costs would vary from the forecast,8

has been passed on to the ratepayers.9

Q HAS CONSUMERS BEEN ABLE TO EARN ITS AUTHORIZED ROE OVER THE10

PAST FEW YEARS?11

A Yes. As shown below, the Company has consistently earned close to, if not above, its12

authorized ROE.13

Table 214

Earned Versus Authorized ROEs1415

Year End Earned ROE Authorized ROE

2010 10.93% 10.5%

2011 10.49% 10.5%

2012 8.63% 10.3%

2013 12.32% 10.3%

2014 12.09% 10.3%

2015 9.81% 10.3%

2016 9.41% 10.3%

13 In the matter of the application of CONSUMERS ENERGY COMPANY for authority to increase itrates for the distribution of natural gas and for other relief, Case No. U-18124, Order, 53 (July 31,2017.)

14 Quarterly Financial Report on Michigan Electric and Natural Gas Utilities June 2017.




Q CAN YOU EXPLAIN THE DIFFERENCE BETWEEN EARNED ROE AND1

AUTHORIZED ROE?2

A The earned ROE is the Company’s actual earnings, as reported to the Michigan Public3

Service Commission, for December of each year. The authorized ROE is the ROE4

that was awarded to the utility by the MPSC during the corresponding year.5

Q WHAT WAS THE NATIONAL AVERAGE AUTHORIZED ROE FOR EACH OF6

THESE YEARS?7

A The table below shows the national average authorized ROE for gas utilities for the8

period 2010 through 2017.9

Table 310

Historical National Average Authorized ROEs1511

Year

National Avg.

Authorized

ROE

2010 10.15%

2011 9.92%

2012 9.94%

2013 9.68%

2014 9.78%

2015 9.60%

2016 9.54%

2017 9.72%

As can be seen, Consumers Energy’s authorized ROE was much higher than12

the national average for each of these years.13

15 See supra note 1.




Flotation Costs

Q WHAT ARE FLOTATION COSTS?1

A Flotation costs include two components. The first component is the actual cost paid2

by the Company to the underwriter for issuing the stock. The second is indirect and3

represents the claimed decrease in the price of the stock resulting from the issuance4

of new shares.5

Q SHOULD FLOTATION COSTS BE INCLUDED AS AN ADJUSTMENT TO ROE?6

A No. The actual cost paid to the underwriter may be expensed, if stock is issued during7

the test year. The indirect cost represents a risk to the shareholder that the price of8

the stock may fluctuate. As stated by the Supreme Court of North Carolina “it is not9

the job of the Commission to protect investors from swings in market prices.”1610

Q DOES THE COMPANY MAKE AN ADJUSTMENT FOR FLOTATION COSTS?11

A Yes, Mr. Maddipati estimated the flotation cost for each company in his proxy group12

and the average flotation cost is 0.14%.17 Consequently, the majority of the Company’s13

ROE calculations are adjusted upwards to reflect a flotation cost adjustment.14

Q SHOULD THE COMPANY’S ESTIMATED ROE BE ADJUSTED TO REFLECT15

FLOTATION COSTS?16

16 Duke Power v. Public Staff, 331 N.C. 215, 225 (1992)

17 Direct Testimony of Srikanth Maddipati, Exhibit A-14, (SM-1), Schedule D-5, at 2.




A No. The Commission has not allowed flotation costs in the past.18 The Company is1

not planning on issuing any stock during the test period. Furthermore, if the Company2

was planning on issuing stock it could expense the issuance costs. However, no3

adjustment for the possible change in the market price is necessary, as ratepayers4

should not be responsible for these changes.5

Q HAS THE COMPANY REQUESTED AN ADJUSTMENT TO ITS ROE TO ACCOUNT6

FOR FLOTATION COSTS IN THE PAST?7

A Yes, in the Company’s pending electric case, No. U-18322, it requested a flotation8

cost adjustment. However, in the Proposal for Decision (PFD) in that case, the9

Administrative Law Judge (ALJ) states that “this PFD finds that Consumers Energy10

has not justified a change in the Commission’s prior determination that flotation costs11

are not recoverable.”19 The Company has not justified a change in this case either.12

As stated above, the flotation cost adjustment adds an additional $5.3 million to the13

Company’s revenue requirement.14

Q WHAT IS YOUR RECOMMENDATION?15

A The Commission should disallow the Company’s recommended flotation cost16

adjustment.17

18 In the matter of the application of CONSUMERS ENERGY COMPANY for authority to increase itsrates for the generation and distribution of electricity and other relief, Case No. U-14347, Opinion andOrder at 24 (Dec. 22, 2005).

19 Case No. U-18322, Notice of Proposal for Decision at 221.




Proxy Group

Q WHAT IS THE PURPOSE OF USING A PROXY GROUP TO DETERMINE THE1

APPROPRIATE RETURN ON EQUITY FOR A REGULATED UTILITY?2

A The proxy group is used to estimate an appropriate return on equity for a utility. It3

should include only those companies that are similar in risk to the subject utility.4

Q WHY ARE PROXY GROUPS RELEVANT TO DETERMINING AN APPROPRIATE5

COST OF EQUITY IN THIS PROCEEDING?6

A Consumers is seeking higher gas rates in this proceeding. Thus, in order to provide a7

ROE that is comparable to Consumers, the proxy group should include companies8

that primarily share common risk. Some of the companies in Consumers’ proxy group9

have operations that extend beyond regulated, natural gas operations.10

Q WHAT FACTORS DID YOU CONSIDER WHEN COMPARING SIMILAR RISK11

LEVELS FOR COMPANIES TO INCLUDE IN THE PROXY GROUP.12

A I have used the same criteria that the Company used when it created its proxy group.13

However, I altered the Company’s proxy group so that the companies better reflect a14

regulated, natural gas utility. That is, I excluded companies that are not classified as a15

natural gas utility by Value Line and do not derive the majority of their operating16

revenues from their natural gas operations.17

Q WHAT PROXY GROUP DID CONSUMERS USE IN ITS ANALYSIS?18

A The Company included the following companies in its proxy group.19

• Atmos Energy Corporation20

• Black Hills Corporation21

• CenterPoint Energy, Incorporated22

• DTE Energy Company23




• Eversource Energy1

• National Fuel Gas Company2

• New Jersey Resources Corporation3

• NiSource Incorporated4

• Northwest Natural Gas Company5

• ONE Gas, Incorporated6

• South Jersey Industries, Incorporated7

• Southwest Gas Holdings, Incorporated8

• Spire, Incorporated9

• Vectren Corporation10

• WEC Energy Group, Incorporated11

Q WHAT COMPANIES MADE UP THE PROXY GROUP IN CONSUMERS’ PREVIOUS12

GAS RATE CASE?13

A The proxy group selection in the previous gas rate case, U-18124, varied from the14

proxy group used in its current gas rate case. The companies included in the proxy15

group were:16


• National Fuel Gas18

• Northwest Natural Gas19


• Southwest Gas Corporation21


• WGL Holdings23

Q DID CONSUMERS USE THE SAME SELECTION CRITERIA IN BOTH CASES?24

A No. In the current case the Company selected its proxy group based on the following25

criteria:26

• Operating company must be classified as a gas utility by S&P Global27

Market Intelligence;28

• Company must be publicly traded and headquartered in the U.S;29

• Company must be paying a dividend;30

• Company must have a 2016 market capitalization greater than $1 billion31

and less than $25 billion;32




• Company must not be a recent merger target or restructuring entity; and1

• Company must have investment grade (IG) rated bonds.2

Q WHAT CRITERIA DID THE COMPANY USE IN THE PREVIOUS RATE CASE TO3

DETERMINE ITS PROXY GROUP?4

In the Company’s previous gas rate case (U-18124) its criteria included the5

following:6

• Categorized as a gas company by Value Line;7

• % regulated gas revenue greater than 35%;8

• Investment grade bond ratings;9

• Must be paying a dividend; and10

• Must not be recently targeted as a merger with another company.11

Q WHAT IS THE MOST SIGNIFICANT DIFFERENCE BETWEEN THE COMPANY’S12

PROXY GROUP IN THIS CASE AND THE ONE IT CHOSE IN CASE NO. U-18124?13

A The Company included companies in its proxy group that are not classified as natural14

gas utilities and includes companies that do not derive the majority of their operating15

revenue from gas operations.16

Q IS CONSUMERS’ PROXY GROUP IN THIS CASE APPROPRIATE?17

A No. The Company’s proxy group includes companies that are not compatible with18

Consumers regulated utility. Specifically, some companies are categorized as electric19

utilities by Value Line and others are categorized as natural gas, diversified. Electric20

utilities and diversified companies are riskier than a regulated, natural gas utility based21

on their operating characteristics. An integrated electric utility has generation,22

transmission and distribution operations. Generation assets have greater risk, due to23

their investment costs and operating requirements. Using these companies in the24

proxy group will produce an incorrect ROE for Consumers. Diversified companies25




include operations such as gas and oil exploration, which are not regulated. In1

addition, one company in Consumers’ proxy group recently acquired a water company2

and should be excluded, because it violates one of the Company’s criteria that a3

company should not be a recent merger target or restructuring entity.4

Q DO ALL OF THE COMPANIES IN CONSUMERS’ PROXY GROUP COMPLY WITH5

MR. MADDIPATI’S SELECTION CRITERIA?6

A No, some of the utilities do not meet Mr. Maddipati’s own criteria and should be7

excluded. For example, he included companies that are classified as multi-utilities by8

S&P. S&P defines multi-utilities as utility companies with significantly diversified9

activities in addition to core electric utility, gas utility and/or water utility operations.10

He also included companies that do not derive the majority of their operating revenues11

from gas operations.12

Q WHY IS IT IMPORTANT THAT CONSUMERS ENERGY UTILIZE A SUITABLE13

PROXY GROUP?14

A When estimating the ROE for a regulated company, the proxy group should match as15

closely as possible to Consumers’ natural gas utility operations. In this case, the16

Commission must determine an appropriate ROE for Consumers based on its17

regulated, natural gas operations only. Therefore, to properly determine the ROE for18

Consumers, the proxy group should include only those companies with risk profiles19

that are similar to a regulated, natural gas utility, including its operations profile and20

revenue profile.21

For example, certain companies in Consumers’ proxy group derive their22

revenue from other businesses, such as electric utility operations, power generation,23




oil and gas exploration and production and coal mining. Black Hills Corporation is1

categorized as an electric utility by Value Line and as “multi-utilities” by S&P. In 2016,2

Black Hills Corporation derived only 53% of its operating revenues from its gas utility.3

In 2015, only 42% of its operating revenues were derived from its gas utility.204

CenterPoint Energy, Inc. is categorized as an electric utility by Value Line and multi-5

utilities by S&P. In 2016, CenterPoint derived only 32% of its operating revenues from6

its natural gas distribution segment.21 DTE Energy is also categorized as an electric7

utility by Value Line and multi-utilities by S&P. In 2016, only 12.5% of the company’s8

operating revenues came from its natural gas segment.229

Q ARE THERE OTHER COMPANIES THAT SHOULD BE EXCLUDED FROM10

CONSUMERS’ PROXY GROUP?11

A Yes, Vectren Corporation and WEC Energy Group, Inc. are also categorized as12

electric utilities by Value Line. S&P categorizes Vectren Corporation and WEC Energy13

Group as “multi-utilities”. Furthermore, in 2016, only 13% of Vectren’s operating14

revenues were derived from its gas utility operations and 87% was derived from its15

electric utility operations.23 For WEC Energy Group, Inc., 88% of its utility revenues16

come from electric sales and only 12% are derived by its gas sales.24 National Fuel17

Gas Company is categorized as being “natural gas, diversified” by Value Line and18

20 SNL Financial, a Subsidiary of S&P Global Market Intelligence, Segment Analysis (Financials).

21 Id.

22 Id.

23 Id.

24 Id.




should be excluded from the proxy group. Companies in the diversified category1

produce, market and transport natural gas. Exploration and production activities are2

also common in this industry. For example, per Value Line, “National Fuel Gas3

Company is engaged in the production, gathering, transportation, distribution and4

marketing of natural gas and oil.”25 In 2017, only 41% of the company’s operating5

revenue was from the utility. 26 The remainder was from exploration and production,6

pipeline and storage, gathering and energy marketing. National Fuel Gas Company’s7

operations are much riskier than a regulated, natural gas company and it should not8

be included in the proxy group. Eversource Energy recently completed its acquisition9

of Aquarion Water Company (December 4, 2017). The acquisition was announced in10

June 2017 and therefore, the company should be excluded. Finally, New Jersey11

Resources Corporation and South Jersey Industries, Incorporated were excluded12

because they derive less than 40% of their operating revenues from their gas13

operations.14

Q BASED ON YOUR ANALYSIS, WHAT COMPANIES SHOULD BE EXCLUDED15

FROM CONSUMERS’ PROXY GROUP?16

A Overall, nine companies should be excluded from Consumers’ proxy group. They17

include:18

• Black Hills Corporation19

• CenterPoint Energy, Incorporated20

• DTE Energy Company21

• Eversource Energy22

• National Fuel Gas Company23

25 Direct Testimony of Srikanth Maddipati, WP-SM-19 at 6.

26 SNL Financial, a Subsidiary of S&P Global Market Intelligence, Segment Analysis (Financials).




• New Jersey Resources Corporation1


• Vectren Corporation3

• WEC Energy Group, Incorporated4

Q WHAT IS YOUR RECOMMENDED PROXY GROUP?5

A My proxy group consists of six companies for which the majority of revenues are6

derived from gas supply/delivery services and are categorized as natural gas utilities.7

These companies meet all of Mr. Maddipatis’ criteria, as well as mine, and are more8

representative of a purely regulated natural gas company. They include:9


• NiSource, Incorporated11

• Northwest Natural Gas Company12

• ONE Gas, Incorporated13

• Southwest Gas Holdings, Incorporated14


Capital Asset Pricing Model

Q PLEASE DESCRIBE THE CAPM.16

A The CAPM is a risk premium method that is used to estimate the ROE. It states that17

the expected return of a security equals the risk-free rate plus a risk premium. Simply18

put, investors require a premium over the risk-free rate if they are going to invest in a19

riskier security. The formula for the CAPM is:20

Expected ROE = Risk-Free Rate + β*Market Risk Premium 21

The equity risk premium for a particular stock is the market risk premium (MRP) times22

the stock’s beta (β). The MRP is the difference between the return on the market on 23

average (i.e., all stocks) and the risk-free rate. Thus, it is the premium that reflects the24

risk on an average stock. Beta is the price volatility of that stock relative to the market25

as a whole. Thus, the risk premium for a specific stock equals the average MRP times26




the beta. Since utility stocks are lower risk than the average, the risk premium for a1

utility stock is lower than the average MRP. Multiplying the beta times the MRP gives2

the appropriate risk premium for the company (or group of comparable companies)3

being studied.4

Q WHAT IS THE STANDARD FORMULA FOR ESTIMATING BETA?5

A Beta is the covariance between a security’s cash flows and that of the market.6

Q WHAT BETA DID THE COMPANY UTILIZE IN ITS CAPM ANALYSIS?7

A The Company’s beta is the average beta of the companies in its proxy group, 0.74.8

The betas for each company are from Value Line.9

Q PLEASE DESCRIBE THE COMPANY’S CAPM METHODS.10

A The Company used two variations of the CAPM method, using two estimates of the11

MRP and two estimates of the risk-free rate.12

Q ARE ANY OF THE COMPANY’S CAPM ANALYSES REASONABLE?13

A No. The first CAPM method, labeled the “Normalized CAPM,” uses a normalized risk-14

free rate of 5.02%, which the Company states is consistent with using a historical risk15

premium of 6.93%.27 The second method, labeled the “Low Interest Rate CAPM,”16

uses a projected yield on the 30-year U.S. Treasury bonds, but a higher equity risk17

premium claiming consistency with “...research indicating higher equity risk premiums18

in low interest rate environments.”28 The Company’s MRP in the Low Interest Rate19

27 Direct Testimony of Srikanth Maddipati at 37-38.





CAPM is 10.03% and based on historical data since only 2011. The risk-free rate is1

the projected average of 3.96%.292

Q WHAT ARE THE RESULTS OF THE COMPANY’S CAPM ANALYSES?3

A The estimated ROEs are 10.27% using the Normalized CAPM method and 11.49%4

using the Low Interest Rate CAPM method.30 These estimates include the flotation5

cost adjustment of 0.14%.6

Q ARE THERE ANY FLAWS WITH THE NORMALIZED CAPM ANALYSIS?7

A Yes. The Normalized CAPM analysis uses a higher, historical risk-free rate of 5.02%8

instead of the forecast rate during the test year of 3.96%. Forecasts of the risk-free9

rate are readily available, as demonstrated in Mr. Maddipati’s testimony and recognize10

more realistic, expected interest rates during the test year and should be used to11

estimate the ROE.12

Q ARE THERE ANY PROBLEMS WITH THE LOW INTEREST RATE CAPM13

ANALYSIS?14

A Yes. The Company used too short of a time frame to determine the MRP, 2011-15

2016.31 A sample of six years is not enough data to represent the long-term MRP. As16

stated in New Regulatory Finance, “Given the significant period-to-period variations in17

the risk premium, altering the sample period when calculating the average is18

dangerous because it can markedly influence the estimate.”32 Therefore, using long-19

29 Id., Exhibit A-14 (SM-1) Schedule D-5 at 2.

30 Id.

31 Id., Exhibit A-14 (SM-1) Schedule D-5 at 10.

32 Public Utilities Reports, Inc., New Regulatory Finance, Roger Morin, PhD at 156 (Jun. 2006).




term market data (available since 1926) is the correct time frame to determine a1

reliable MRP.2

Q HAS THE COMPANY USED THIS METHOD BEFORE?3

A Yes. In Case No. U-18322, it used the exact same methodology to estimate the4

electric ROE for Consumers Energy electric. However, as noted in the PFD, “This5

PFD finds that Mr. Maddipati has not justified his choice of inputs for the CAPM….”336

Therefore, the CAPM methodologies should be ignored.7

Q WHAT ARE THE ROE RESULTS IF THE COMPANY WERE TO USE THE8

AVERAGE BETA ESTIMATE, THE HISTORICAL MARKET RISK PREMIUM AND9

THE CORRECT PROXY GROUP?10

A As shown in Exhibit AB-9, using the historical MRP of 6.93%, a risk-free rate of 3.96%11

and the average beta of 0.69 results in an average ROE of 8.76%, without adjustment12

for flotation costs.13

3.96% + (.69 * 6.93%) = 8.76%.14

Q MR. MADDIPATI STATES THAT IT IS INCONSISTENT TO USE THE CURRENT15

RISK-FREE RATE WITH THE HISTORICAL RISK PREMIUM. DO YOU AGREE?16

A No. The historical risk premium is based on 91 years of data (1926 – 2016) and17

provides a good approximation of future risk premiums and is appropriate to use with18

a forward looking risk-free rate.19





Q WHY DOES LOOKING SO FAR INTO THE PAST PROVIDE A GOOD1

APPROXIMATION OF FUTURE RISK PREMIUMS?2

A Expected returns are not directly observable, therefore using a long-term historical3

observation is preferable. As stated in New Regulatory Finance “it is reasonable to4

believe that long-run average realized returns provide an unbiased estimate of what5

were expected returns.”34 There may be significant variations in the risk premium over6

short periods of time. The long-term data will smooth out these variations and provide7

a more reliable estimate of the market risk premium.8

Q ARE YOU ABLE TO QUANTIFY THE DIFFERENCE IN VARIANCE BETWEEN9

USING 91 YEARS, AS YOU SUGGEST, AND 6 YEARS, AS MR. MADDIPATI10

PROPOSES?11

A Yes. Mr. Maddipati’s short-term market risk premium is 10.03%, as compared to the12

historical, long-term market risk premium of 6.93%. This a difference of 310 basis13

points. The higher, short-term market risk premium would serve to inflate the14

estimated ROE.15

Q PLEASE DESCRIBE MR. MADDIPATTI’S ECAPM ANALYSIS.16

A Mr. Madipatti’s Empirical Capital Asset Pricing Model (ECAPM) analyses are similar17

to his CAPM analyses except that he adjusts the formula using a component called18

alpha (α). The formula for his ECAPM analysis is: 19

Ke =Rf + α + F + β x (Rp – α) 20





Where:1

Ke = the estimated cost of equity2

Rf = the risk-free rate3

α = alpha 4

F = flotation cost adjustment5

β = beta 6

Rp = the market risk premium7

The value he used for alpha is 1.5%.35 The ECAPM analyses were used to estimate8

two ROEs, similar to his CAPM analyses. The first is labeled the Normalized ECAPM9

ROE and estimated similar to his Normalized CAPM analysis, except he includes the10

alpha component. This produced an ROE of 10.66%, including flotation costs.36 The11

second is labeled the Low Interest Rate ECAPM ROE and again, is similar to his Low12

Interest Rate CAPM analysis, except it is adjusted using alpha. The estimated ROE13

using the Low Interest Rate ECAPM analysis is 11.88%, including flotation costs.3714

Q CAN YOU PLEASE EXPLAIN WHAT ALPHA REPRESENTS?15

A Alpha is an econometrically estimated adjustment that is supposed to account for the16

fact that over the long term it has been shown that companies with betas less than one17

are under-estimated; that is, their risk is actually higher than the risk defined by the18

beta. Companies with betas greater than one are over-estimated; that is, their risk is19

actually lower than the risk shown by the beta.20

35 Direct Testimony of Srikanth Maddipati, Exhibit A-14 (SM-1) Schedule D-5 at 3.

36 Id.

37 Id.




Q WHAT IMPACT DOES ALPHA HAVE ON THE ECAPM ANALYSES?1

A The alpha produces an over-stated ROE.2

Q PLEASE EXPLAIN.3

A The betas used by Mr. Maddipati in his CAPM analyses have been adjusted by Value4

Line to account for the underestimation (or overestimation) of the ROE. There is no5

need to perform an ECAPM analysis as it results in re-adjusting the formula to capture6

a phenomenon that the adjusted beta has already corrected.7

Risk Premium Method

Q PLEASE DESCRIBE THE RISK PREMIUM METHOD.8

A The risk premium method estimates the return on equity for a utility as the sum of a9

bond yield plus a risk premium. The bond yield is the return on the long-term10

government bond plus the corporate spread on utility bond yields. The risk premium11

is a measure of the additional return an investor requires due to the additional risk of12

the security. The risk premium is the measure of the difference between the historical13

return on gas utility stocks and the yield on utility bonds.14

Q WHAT RETURN ON EQUITY DID THE COMPANY CALCULATE USING ITS RISK15

PREMIUM METHODS?16

A Its ROEs are 12.38% and 13.95%.38 These do not include flotation cost adjustments.17

Q HAVE YOU REVIEWED CONSUMERS’ RISK PREMIUM ANALYSES?18

A Yes. Similar to its CAPM analyses, Consumers’ relies on two risk premium analyses,19

38 Id. at 4.




the Normalized Risk Premium analysis and the Low Interest Rate Risk Premium1

analysis.2

Q DO YOU SEE ANY PROBLEMS WITH HOW THE COMPANY CONDUCTED THE3

NORMALIZED RISK PREMIUM ANALYSIS?4

A Yes, the Normalized method relies on the historical spread of gas utility common5

stocks over utility bonds and the historical long-term utility bond yield.6

Q WHY IS THAT INCORRECT?7

A. This approach grossly overstates the current estimated bond yield and produces an8

ROE that is too high (12.38%).399

Q ARE THERE ANY PROBLEMS WITH THE COMPANY’S LOW INTEREST RATE10

RISK PREMIUM ANALYSIS?11

A Yes, the Low Interest Rate Risk Premium analysis uses a short-term period (six years)12

to estimate the historical spread on gas utility common stock over utility bond yields13

and the projected 30-Year Treasury yield to estimate a cost of equity that is, again, too14

high (13.95%).4015

Q WHAT ASSUMPTIONS DID CONSUMERS USE IN APPLYING THE NORMALIZED16

RISK PREMIUM METHOD?17

A The Normalized Risk Premium method estimates the historical spread of gas utility18

common stock returns over historical utility bonds (3.90%) over the period 1952 -19

39 Id.

40 Id.




2016.41 The historical long-term government bond return (6.93%) is then added to a1

corporate spread based on the S&P bond ratings to estimate the current bond yield.422

The current bond yields are:3

• A rated: 8.18%;4

• A- rated: 8.33%;5

• BBB+ rated: 8.39%; and6

• BBB rated: 9.01%.437

The historical spread is then added to the current bond yields to estimate the8

cost of equity. The average of the four calculations is 12.38%.9

Q IS THIS ANALYSIS CORRECT?10

A No, the historical long-term government bond yield that is used is incorrect. There is11

an error in Mr. Maddipatti’s calculations and instead of using his calculation of 5.02%12

for the historical long-term government bond yield, the historical market risk premium13

of 6.93% is used.4414

Q WHAT IS THE ROE USING THE CORRECT LONG TERM GOVERNMENT BOND15

YIELD?16

A The cost of equity is lower by 191 basis points, to 10.47%. See Exhibit AB-10 for17

the details.18

41 Id. at 11.

42 Id. at 10.

43 Id.at 4.

44 Id. at 10.




Q HOW IS THE LOW INTEREST RATE RISK PREMIUM ANALYSIS DIFFERENT?1

The Low Interest Rate Risk Premium analysis measures the historical spread of gas2

utility common stock returns over utility bonds for the years 2011-2016 (8.45%).45 This3

spread of 8.45% is then added to the projected long-term government bond yield plus4

the corporate spreads for the A – BBB rated bonds to estimate the cost of equity. The5

estimated bond yields are:6

• A rated: 5.21%;7

• A- rated: 5.36%;8

• BBB+ rated: 5.42% and9

• BBB rated: 6.04%.4610

The average of the four ROE estimates is 13.95%.4711

Q ARE EITHER OF THE COMPANY’S RISK PREMIUM METHODS APPROPRIATE IN12

SETTING CONSUMERS’ ROE IN THIS CASE?13

A No. The Normalized Risk Premium analysis is inappropriate. Similar to its CAPM and14

ECAPM analyses, Consumers relies on historical long-term government bond yield15

data rather than forecasted rates. Furthermore, there is an error in its Normalized Risk16

Premium analysis that inflates its estimated return on equity by 191 basis points. The17

Low Interest Rate risk premium method relies on a short-term estimate of the projected18

long-term government bond yield.19

45 Id. at 4.

46 Id.

47 Id.




Q CAN YOU PLEASE DESCRIBE THE ERROR AND EXPLAIN HOW IT AMOUNTS1

TO SUCH A LARGE INCREASE?2

A The Company used the incorrect historical government bond return (6.93%) in its ROE3

calculations. Mr. Maddipati intended to use his estimate of 5.02% instead. This error4

increased the average estimated ROE by 191 basis points, from 10.47% to 12.38%.5

Q HAVE YOU IDENTIFIED ANY OTHER ISSUES WITH THE ANALYSES?6

A Yes, the Low Interest Rate risk premium analysis relies on a short-term average, six7

years, to estimate the spread of gas utility common stock returns over utility bond8

yields. This limited set of data is not a reliable metric to determine the long-term risk9

premium. As noted in the PFD from the Company’s pending electric rate case, “That10

the cost of equity capital may be difficult to project does not justify using a small subset11

of historical data from a time period that is not expected to look like the projection12

period.”4813

Q WOULD THE RESULTS OF THE COMPANY’S RISK PREMIUM METHOD CHANGE14

IF THEY WERE BASED ON THE LONG-TERM HISTORICAL SPREAD OF GAS15

UTILITY COMMON STOCK OVER UTILITY BONDS AND THE PROJECTED LONG-16

TERM GOVERNMENT BOND RETURN?17

A Yes. The cost of equity results are shown on Exhibit AB-11 using the Company’s18

data:19





Table 31Revised Risk Premium Analysis2

Amount A A- BBB+ BBB

Historical Spread 1952-2016 3.90% 3.90% 3.90% 3.90%

Current Estimated Bond Yield 5.21% 5.36% 5.42% 6.04%

Cost of Equity 9.11% 9.26% 9.32% 9.94%

Consumers’ bond rating is A and the estimated ROE for an A rated company is 9.11%,3

more than 400 basis points lower than the average Risk Premium recommendation of4

13.17% ((13.95%+12.38%)/2).495

Q WHY IS THERE SUCH A LARGE VARIATION IN THE COMPANY’S ESTIMATED6

ROE USING THE RISK PREMIUM AND YOUR REVISED VERSION?7

A There are several reasons. First, the Company has a mistake in its Normalized Risk8

Premium methodology that overstates the ROE by 191 basis points. Second, the9

Company overestimates the current bond yield, and third, it uses a short time frame10

(six years) to estimate the spread of gas utility stock over utility bonds. Finally, the11

Company estimates the ROE based on the average results using all utility bond yields,12

instead of the A-rated bonds only.13

Discounted Cash Flow Method

Q PLEASE DESCRIBE THE DISCOUNTED CASH FLOW METHOD.14

A The discounted cash flow model is used by investors to determine the present value15

of a stock, based on future cash flows (dividends), which are discounted by the stock’s16

known return and its forecast growth.17





The formula is:1

� =�

��2

Where:3

P = current stock price4

D = dividend yield5

r = rate of return6

g = growth rate7

We can re-arrange the formula thus:8

� =D

P+ �9

In other words, the expected return equals (1) the current dividend rate, plus (2) the10

expected growth in dividends. The expected growth in dividends is also measured by11

the expected growth in earnings.12

Q PLEASE DESCRIBE CONSUMERS’ DISCOUNTED CASH FLOW ANALYSIS.13

A The Company performed two DCF analyses, one based on analysts’ consensus14

dividend growth rates from Institutional Brokers' Estimate System (IBES), which15

results in an ROE of 10.18% and one based on the comparable companies forecast16

earnings or dividend growth rates provided in the companies’ presentations to17

analysts. The second method results in an ROE of 9.55%.50 The estimated ROEs18

using the DCF analyses include flotation costs.19

50 Id. at 5.




Q DO YOU AGREE WITH CONSUMERS’ DCF ANALYSES?1

A No. The first DCF analysis relies on the consensus growth in dividends per share.2

Investors’ growth expectations typically rely on trends in earnings, which will support3

future dividends. Even Mr. Maddipati admits: “…a Company may have dividend4

growth that outpaces earnings growth, consistently outperforms guidance, or have5

irregular and other one-time dividends, all of which would cause the DCF model to6

misstate ROE.” 51 (emphasis added) As noted in New Regulatory Finance,” In most7

cases, it is necessary to use earning’s forecasts rather than dividend forecasts due to8

the extreme scarcity of dividend forecasts compared to the widespread availability of9

earnings forecasts.” 5210

Q WHAT IS THE ESTIMATED ROE USING YOUR MODIFIED PROXY GROUP AND11

EARNINGS GROWTH RATES?12

A The average estimated ROE is 8.84%. This is based on Consumers’ DCF analysis13

and adjusted proxy group. I substituted forecast growth rates for earnings instead of14

the forecast growth rate in dividends using data from Value Line, Yahoo! Finance and15

Zacks. I also eliminated the flotation cost adjustment, for the reasons discussed16

above. The details of my analysis are shown in Exhibit AB-12.17

Q DID YOU MAKE ANY OTHER ADJUSTMENTS?18

A Yes, I adjusted the dividend yield to reflect one half of the forecast earnings growth to19

reflect any quarterly adjustments during the year. Dividends are paid quarterly and20






are usually increased once per year. Multiplying the dividend yield by one half of the1

earnings growth rate reflects the timing of dividend payments throughout the year.2

Q IS THE COMPANY’S SECOND DCF ANALYSIS SIMILARLY FLAWED?3

A Yes. The second DCF analysis relies on the growth outlook as provided in investor4

presentations for the companies in its proxy group. Most are based on limited5

forecasts of growth in dividends, not earnings and are not representative of earnings6

forecasts.7

Q PLEASE SUMMARIZE YOUR COMMENTS REGARDING CONSUMERS’ DCF8

ANALYSES.9

A The DCF estimated ROEs are based on dividend growth rates plus flotation costs and10

produce overstated ROEs. Earnings growth rates should be used in the DCF model11

as earnings growth is a driver for dividend growth. Based on my modified proxy group,12

and using forecast earnings growth rates, eliminating flotation costs and adjusting the13

dividend to reflect one-half of the earnings growth rate results in a more realistic ROE14

of 8.84%.15

Comparable Earnings Method

Q PLEASE DESCRIBE THE COMPANY’S APPLICATION OF THE COMPARABLE16

EARNINGS METHOD.17

A The Comparable Earnings method estimates Consumers’ ROE by analyzing the18

estimated earnings per share (EPS) and book value per share for the period of 2020-19

2022 for each of the utilities in the Company’s proxy group. The estimated EPS are20

divided by the corresponding book value to estimate the ROE. Its Comparable21




Earnings analysis produces an average ROE of 11.08%.531

Q DO YOU HAVE ANY COMMENTS REGARDING THE COMPARABLE EARNINGS2

METHOD?3

A Yes. The Comparable Earnings method overstates the ROE. The Company included4

“outliers” in its analysis, such as CenterPoint Energy (16.50%), National Fuel Gas5

Company (16.96%) and South Jersey Industries, Inc. (7.20%). These extreme outliers6

should not be included. Excluding these three outliers lowers the ROE to 10.46% or7

by 62 basis points.8

In addition, the Comparable Earnings method represents a forecast return on9

equity and not a required return or cost of equity and therefore should not be relied10

upon to estimate the Company’s ROE. However, I estimated the ROE using the11

comparable earnings method and my group of comparable companies which produces12

an average ROE of 10.12% as shown on Exhibit AB-13.13

Summary

Q PLEASE SUMMARIZE YOUR CRITICISMS OF THE COMPANY’S ROE14

ANALYSES.15

A The Company’s recommended ROE of 10.5% overstates the revenue deficiency and16

would result in residential customers paying an additional $12.33 per customer per17

year, based on the national average authorized ROE for 2017 of 9.72%.18





The Company’s recommended ROE does not recognize its reduced risk due1

to the use of a Gas Revenue Decoupling Mechanism and the Investment Recovery2

Mechanism.3

The analysis adds a flotation cost adjustment to the ROE estimates, which is4

not warranted because the Commission has disallowed flotation costs in prior5

decisions. Furthermore, Consumers Energy has no plans to issue stock during the6

test period. If the Company were to issue stock and collect flotation costs, only those7

costs associated with the issuance should be collected. Accordingly, the flotation cost8

adjustment should be rejected.9

Consumers’ proxy group includes companies that are not comparable in risk10

to Consumers. It includes companies that are riskier than a regulated, natural gas11

utility, such as electric utility companies and companies that are involved in gas and12

oil exploration.13

The Company’s ROE analyses relies on nine methods to estimate an ROE for14

Consumers. The CAPM methods are not reliable. Its Normalized CAPM analysis15

relies on a historical risk-free rate when a forecast risk-free rate is available and the16

Low Interest Rate CAPM relies on a short time period (six years) to determine the17

MRP.18

The ECAPM analyses produces over-stated ROEs by making an unnecessary19

adjustment to the CAPM formula.20

The Risk Premium methods have issues that are similar to the CAPM analyses.21

The Normalized Risk Premium method uses historical long-term government bond22

yields when projected bond yields are readily available. There is also an error in the23

Normalized Risk Premium analysis that results in a ROE that is overstated by 19124




basis points. The Low Interest Rate Risk Premium method uses short-term spread of1

gas utility stock over utility bond yields that is based on a short-term period (six years)2

and results in an over-stated ROE.3

The DCF analyses use forecast dividend growth rates instead of earnings4

growth rates. Forecast earnings growth rates provide a better estimate of dividend5

growth rates because earnings are the main driver for dividend growth.6

The Comparable Earnings method overstates the ROE and does not estimate7

the required cost of equity but only provides a forecast of return on equity.8


4. Capital Structure


4. CAPITAL STRUCTURE

Q WHAT IS CONSUMERS’ PROPOSED PERMANENT CAPITAL STRUCTURE?1

A Consumers is proposing a financial or “permanent” capital structure consisting of2

52.49% common equity, 0.29% preferred stock and 47.21% debt.543

Q HOW DID CONSUMERS DETERMINE ITS CAPITAL STRUCTURE?4

A Consumers’ capital structure witness, Mr. Denato, used the actual balances of long-5

term debt, preferred stock, common equity, deferred income taxes and investment tax6

credit as of July 31, 2017. He then adjusted these amounts to reflect an average test7

year balance ending June 30, 2019.558

Q HOW DID MR. DENATO DETERMINE THE COMMON EQUITY BALANCE?9

A Mr. Denato adjusted the utility’s common equity balance by $320 million.56 First, he10

determined the net income for the utility ending December 31, 2016, then used this11

amount to determine the retained earnings, based on an 80% payout ratio. The12

retained earnings amount is $122.8 million.57 The 13-month average for retained13

earnings is $174 million.58 Second, he made a $146 million adjustment for new equity14

infusions: $100 million in January 2018 and another planned equity infusion of $10015

million by January 2019. The 13-month average for the period ending December 31,16

54 Direct Testimony of Andrew J. Denato, Exhibit No. A-14 (AJD-2), Schedule D-1.

55 Id. at 5.

56 Id.

57 Id. at 6.

58 Id., Exhibit No. A-14 (AJD-2), Schedule D-1a at 3.




2017 is $146 million.59 Adding $320 million to the equity balance results in a 52.49%1

common equity ratio. Mr. Denato states: “This percentage is in line with the2

Company’s goal to maintain a permanent equity ratio consistent with the Company’s3

recent actual equity ratios and also with recently approved rate cases in the low 50%4

range.”605

Q HAS THE COMMISSION PREVIOUSLY ADDRESSED CONSUMERS’6

PERMANENT CAPITAL STRUCTURE?7

A Yes. In its July 31, 2017 Order in Docket No. U-18124, the Commission stated: “The8

Commission cannot overemphasize the company’s responsibility to rebalance its9

equity and debt capital…Consumers shall, in its next rate case, articulate its strategy10

to return to a balanced capital structure and the steps it intends to take to reach its11

stated goal, or the Commission will have to consider using its regulatory authority to12

rebalance Consumers’ capital structure.”6113

Q DOES CONSUMERS’ PROPOSED CAPITAL STRUCTURE RESULT IN14

MOVEMENT TOWARDS ITS 50/50 GOAL?15

A Yes, but not by much. The utility’s authorized common equity ratio in its previous rate16

case was 53.10%.6217

Q WHY SHOULD THE COMMISSION REJECT CONSUMERS’ PROPOSED CAPITAL18

STRUCTURE?19

59 Direct Testimony of Andrew J. Denato at 6.

60 Id. at 7.

61 Case No. U-18124, Order at 45-46.

62 Direct Testimony of Andrew J. Denato at 9.




A Consumers’ common equity ratio is too high, especially in light of its overstated1

requested ROE of 10.5%. The utility can maintain its strong credit ratings and2

implement its capital expenditure program with a lower equity ratio, while at the same3

time taking advantage of low interest rates. A higher common equity ratio will increase4

costs to ratepayers because equity is more expensive than debt.5


A I recommend that the Commission lower Consumers’ requested common equity ratio7

by 100 basis points to 51.49%. This moves Consumers closer to its goal of a 50/508

debt-to-equity ratio, as required by the Commission, and more quickly than what is9

proposed by the Company. This adjustment represents a gradual change in the10

Company’s equity ratio and lowers the equity by $128 million and increases the11

amount of long-term debt by the same amount. The effect of the adjustment to the12

debt-to-equity ratio is a decrease in the revenue requirement of $4.8 million (assuming13

a 9.72% ROE). The derivation of the $4.8 million is shown in Exhibit AB-14.14


5. Conclusion


5. CONCLUSION

Q PLEASE SUMMARIZE YOUR RECOMMENDATIONS.1

A The Commission should adopt the following recommendations:2

• Award Consumers Energy an ROE that reflects the revisions to3Consumers’ analyses and recognizes its lower risk. A lower ROE4would allow Consumers to remain financially sound and attract new5investors, while balancing the interest of ratepayers in paying fair and6reasonable rates and not reward shareholders with windfall profits.7

• Adjust Consumers’ permanent capital structure to 51.49% common8equity, 48.21% debt and 0.29% preferred equity.9

Q DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?10

A Yes.11


Appendix A


APPENDIX A

Qualifications of Billie S. LaConte


A Billie S. LaConte. My business mailing address is 12647 Olive Blvd., Suite 585, St.2

Louis, Missouri 63141.3


A I am an energy advisor and am currently employed by J. Pollock, Incorporated as an5

Associate Consultant.6


A I have a Bachelor of Arts in Mathematics from Boston University and a Master’s in8

Business Administration from Washington University.9

Upon graduation in May 1995, I joined Drazen Consulting Group, Inc. (DCGI).10

DCGI was incorporated in 1995 assuming the utility rate and economic consulting11

activities of Drazen Associates, Inc., active since 1937. I joined J.Pollock in May 2015.12

During my tenure at DCGI and J.Pollock my work focused on cost allocation,13

rate design, sales and price forecasts, power cost forecasting, electric restructuring14

issues, cost of capital (return on equity) issues and contract interpretation.15

I have been engaged in a wide range of consulting assignments including16

energy and regulatory matters in both the United States and several Canadian17

provinces. This included advising clients on economic and strategic issues concerning18

the natural gas pipeline, oil pipeline, electric, wastewater and water industries. I19

prepared cost allocation and rate design studies to provide timely support to clients20

engaged in settlement negotiations in electric and gas utilities, provided power cost21


Appendix A


forecasting studies to assist clients in project planning and negotiated contracts with1

electric utilities for standby services and interruptible rates. I have also prepared2

studies on electric and gas utilities’ performance-based rates (PBR) and3

benchmarking programs to evaluate their success and to provide recommendations4

on methods to be used. I worked on contract interpretation to resolve contract disputes5

for several clients.6

I have worked on various projects located in several jurisdictions including7

Arkansas, Georgia, Iowa, Maine, Michigan, Minnesota, Missouri, Virginia, Alberta,8

British Columbia, Quebec and Nova Scotia. I have provided financial and cost of9

service analysis for natural gas pipelines certificate approval from the Federal Energy10

and Regulatory Commission (FERC) and the Canadian National Energy Board (NEB).11

I have testified before the Missouri Public Service Commission on cost allocation, rate12

design, cost of capital and other matters, the Alberta Energy and Utilities Board on13

power cost forecasting issues, electric restructuring issues, sales and price forecasts14

and cost allocation issues. I similarly testified before the Iowa Utilities Board, the St.15

Louis Metropolitan Sewer District Commission, the Nova Scotia Utility and Review16

Board, the Arkansas Public Service Commission, and the Minnesota Public Service17

Commission.18

Q PLEASE DESCRIBE J. POLLOCK, INCORPORATED.19

A J.Pollock assists clients to procure and manage energy in both regulated and20

competitive markets. The J.Pollock team also advises clients on energy and21

regulatory issues. Our clients include commercial, industrial and institutional energy22

Consumers. J.Pollock is a registered Class I aggregator in the State of Texas.23

Appendix BTestimony Filed in Regulatory Proceedings

by Billie S. LaConte


REGULATORY


160103 ENTERGY ARKANSAS GAS, INC. Arkansas Gas Consumers, Inc. 17-050-U Surrebuttal AR Asset Management Agreement Proposal 1/12/2018

160103 ENTERGY ARKANSAS GAS, INC. Arkansas Gas Consumers, Inc. 17-050-U Direct AR Asset Management Agreement Proposal 12/8/2017

160703 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 16-036-FR Settlement Support AR Support of Settlement 10/31/2017

160703 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 16-036-FR Direct AR Forecast Revenues, Cost of Debt, Revenue Requirement

and Capital Additions

10/4/2017


Equity

18322 Rebuttal MI Return on Equity 9/7/2017


Equity

18322 Direct MI Return on Equity, Capital Structure 8/10/2017

160103 CENTERPOINT ENERGY RESOURCES CORP Arkansas Gas Consumers, Inc. 17-010 Settlement Support AR Support of Settlement 7/31/2017

160103 CENTERPOINT ENERGY RESOURCES CORP Arkansas Gas Consumers, Inc. 17-010 Direct AR Rate of Return, Capital Structure, Labor Expense 7/3/2017

160703 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 16-036-FR Settlement Support AR Support of Settlement 10/24/2016

160703 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 16-036-FR Direct AR Rate of Return, Forecast Revenue, Capitalization 9/30/2016

160301 METROPOLITAN EDISON COMPANY;

PENNSYLVANIA ELECTRIC COMPANY AND WEST

PENN POWER

MEIUG, PICA and WPPII 2016-2537349,

2016-2537352,

2016-2537359

Surrebuttal PA Return on Equity 8/31/2016

160301 METROPOLITAN EDISON COMPANY;

PENNSYLVANIA ELECTRIC COMPANY AND WEST

PENN POWER

MEIUG, PICA and WPPII 2016-2537349,

2016-2537352,

2016-2537359

Direct PA Return on Equity 7/22/2016

151101 NORTHERN STATES POWER Xcel Large Industrials 15-826 Direct MN Return on Equity, Multi-Year Rate Plan 6/14/2016

160103 CENTERPOINT ENERGY RESOURCES CORP Arkansas Electric Energy Consumers, Inc. 15-098-U Surrebuttal AR Return on Equity, Formula Rate Plan, Capital Structure 6/7/2016

160103 CENTERPOINT ENERGY RESOURCES CORP Arkansas Electric Energy Consumers, Inc. 15-098-U Direct AR Return on Equity, Captial Structure 4/14/2016

111506 MISSOURI-AMERICAN WATER COMPANY BJC Healthcare WR-2011-0337 Rebuttal MO Return on Equity 1/19/2012

111506 MISSOURI-AMERICAN WATER COMPANY BJC Healthcare WR-2011-0337 Direct MO Return on Equity 11/17/2011

101479 METROPOLITAN ST. LOUIS SEWER DISTRICT Barnes-Jewish Hospital N/A Supplemental MO Rate Model 9/16/2011

101479 METROPOLITAN ST. LOUIS SEWER DISTRICT Barnes-Jewish Hospital N/A Surrebuttal MO Rate Increase, CIRP, Consent Decree 8/19/2011

101479 METROPOLITAN ST. LOUIS SEWER DISTRICT Barnes-Jewish Hospital N/A Rebuttal MO Rate Increase, CIRP, Consent Decree 7/18/2011

101481 AMEREN UE Missouri Energy Group ER-2011-0028 Surrebuttal MO Return on Equity, Energy Efficiency Cost Recovery 4/15/2011

45




REGULATORY


101481 AMEREN UE Missouri Energy Group ER-2011-0028 Rebuttal MO Return on Equity, Energy Efficiency Cost Recovery 3/25/2011

101481 AMEREN UE Missouri Energy Group ER-2011-0028 Direct MO Return on Equity 2/8/2011

101482 AMEREN UE Missouri Energy Group EO-2010-0255 Direct MO Prudence Audit of FAC Periods 1 and 2 11/22/2010

101461 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 09-084-U Direct - In Support AR Supporting the Proposed Settlement Agreement 5/11/2010

101461 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 09-084-U Surrebuttal AR Return on Equity 4/14/2010

101461 ENTERGY ARKANSAS, INC. Arkansas Electric Energy Consumers, Inc. 09-084-U Direct AR Return on Equity 2/26/2010

091450 AMEREN UE Missouri Energy Group ER-2010-0036 Direct MO Energy Efficiency Costs 12/18/2009

081427 AMEREN UE Missouri Energy Group ER-2008-0318 Surrebuttal MO Return on Equity 11/5/2008

081427 AMEREN UE Missouri Energy Group ER-2008-0318 Direct MO Return on Equity, Off-System Sales 8/28/2008

061404 METROPOLITAN ST. LOUIS SEWER DISTRICT Missouri Energy Group N/A Rebuttal MO Long-Term Financial Plan, Capital Financing 5/2/2007

061402 AMEREN UE Missouri Energy Group ER-2007-0002 Surrebuttal MO Return on Equity, Interruptible Demand, Response Pilot 2/27/2007

061402 AMEREN UE Missouri Energy Group ER-2007-0002 Direct MO Interruptible Rate 12/29/2006

061402 AMEREN UE Missouri Energy Group ER-2007-0002 Direct MO Return on Equity, Off-System Sales, Sharing Mechanism,

10% Cap on Residentials

12/15/2006

041346 AMEREN UE Missouri Energy Group EA-2005-0180 Rebuttal MO Economic Analysis 1/31/2005

041336 NOVA SCOTIA POWER INC. Avon Valley Greenhouses NSUARB-P-881 Direct NS Cost of Capital 10/12/2004

031300 MISSOURI-AMERICAN WATER COMPANY Missouri Energy Group WR-2003-0500 Surrebuttal MO Working Capital, Return on Equity, Cost Allocation 12/5/2003

031300 MISSOURI-AMERICAN WATER COMPANY Missouri Energy Group WR-2003-0500 Rebuttal MO Rate Design 11/10/2003

031300 MISSOURI-AMERICAN WATER COMPANY Missouri Energy Group WR-2003-0500 Direct MO Return on Equity, Acquisition Adjustment, Cash Working

Capital

10/3/2003

031296 METROPOLITAN ST. LOUIS SEWER DISTRICT Missouri Energy Group N/A Direct MO Revenue Requirement, Financial Planning 4/22/2003

021270 INTERSTATE POWER AND LIGHT COMPANY Lee County Energy Users Group- Direct RPU-02-3 Surrebuttal IA Revenue Requirement, Return on Equity 9/19/2002

021271 METROPOLITAN ST. LOUIS SEWER DISTRICT Missouri Energy Group N/A Surrebuttal MO Revenue Requirement, Capital Financing 8/13/2002

46




REGULATORY


021271 METROPOLITAN ST. LOUIS SEWER DISTRICT Missouri Energy Group N/A Surrebuttal MO Revenue Requirement, Captial Financiaing, Cost

Allocation

7/28/2002

021270 INTERSTATE POWER AND LIGHT COMPANY Lee County Energy Users Group- Direct RPU-02-3 Direct IA Revenue Requirement, Return on Equity 7/26/2002

021271 METROPOLITAN ST. LOUIS SEWER DISTRICT Missouri Energy Group N/A Rebuttal MO Revenue Requirement, Capital Financing 7/10/2002

47

Regulatory Research Associates, an offering of S&P Global Market Intelligence© 2018 S&P Global Market Intelligence

Lisa Fontanella, CFA Principal Analyst

Sales & subscriptions: [email protected]

Enquiries: [email protected]

Rate case activity was brisk in 2017. The average ROE authorized electric utilities was 9.74% in rate cases decided in 2017, a record low, albeit marginally below 9.77% in 2016. There were 53 electric ROE determinations in 2017, versus 42 in 2016. This data includes several limited issue rider cases; excluding these cases from the data, the average authorized ROE was 9.68% in rate cases decided in 2017, marginally up from 9.6% in 2016. The differential in electric authorized ROEs is largely driven by Virginia statutes that authorize the State Corporation Commission to approve ROE premiums of up to 200 basis points for certain generation projects (see the Virginia Commission Profile).

For vertically-integrated electric utilities, the average ROE authorized was 9.8% in 2017, versus 9.77% in 2016. For electric distribution utilities, the average ROE authorized was 9.43% in 2017, versus 9.31% in 2016.

The average ROE authorized gas utilities was 9.72% in 2017 versus 9.54% in 2016. There were 24 gas cases that included an ROE determination in 2017, versus 26 in 2016. RRA notes that the 2017 data includes an 11.88% ROE determination for an Alaska utility. Absent this "outlier," the 2017 gas ROE average is 9.63%.

In 2017, the median authorized ROE for all electric utilities was 9.6%, versus 9.75% in 2016. For gas utilities, the median authorized ROE in 2017 was 9.6%, versus 9.5% in 2016.

Over the last several years, the persistently low interest rate environment has put a downward pressure on authorized ROEs. As shown in the graph below, the annual average ROE has generally declined since 1990 and has been below 10% for electrics since 2014, and below 10% for gas utilities since 2011. In addition, after reaching a low in 1999, the number of rate case decisions for energy companies has generally increased over the last several years, peaking in 2010 and again in 2017.

There were 129 electric and gas rate cases resolved in 2017, 116 in 2016, 92 in 2015, 99 in 2014, 100 in 2013, and 110 in 2012, and this level of rate case activity remains robust compared to the late 1990s/early 2000s. Increased costs associated with environmental compliance, generation and delivery infrastructure upgrades and expansion, renewable generation mandates and

January 30, 2018spglobal.com/marketintelligence

RRA Regulatory Focus Major Rate Case Decisions 2017

[email protected];printed 2/6/2018

MPSC Case No.:U-18424Exhibit: Witness: Billie S. LaConteDate: February 2018 Page 1 of 13

AB-6

2 | S&P Global Market Intelligence

Regulatory Focus: Major Rate Case Decisions

employee benefits argue for the continutation of an active rate case agenda over the next few years.

In addition, if the Federal Reserve continues its policy initiated in December 2015 to gradually raise the federal funds rate, utilities eventually would face higher capital costs and would need to initiate rate cases to reflect the higher capital costs in rates. Since the December 2015 hike, the Fed has increased the federal funds an additional four times, the latest hike in December 2017 to a target range of 1.25% to 1.5%. The Fed expects to continue to raise rates gradually in 2018 as the U.S. economy, including labor markets, remain strong. An increase in the rate of price inflation would point to additional Fed tightening, but a significant weakening in the economy would likely cause the Fed to reconsider further interest rate hikes. Also, higher interest rates and borrowing costs would increase the U.S. budget deficit, which is already quite significant, and is expected to further increase due to the enactment in December 2017 of tax reform legislation.

Included in tables on pages 7 and 8 of this report are comparisons, since 2006, of average authorized ROEs by settled versus fully litigated cases, general rate cases versus limited issue rider proceedings and vertically integrated cases versus delivery only cases.

As shown in the graphs and tables, for both electric and gas cases, no pattern exists in average annual authorized ROEs in cases that were settled versus those that were fully litigated. In some years, the average authorized ROE was higher for fully litigated cases, in others it was higher for settled cases, and in a few years the authorized ROE was similar for fully litigated versus settled cases.

Regarding electric cases that involve limited issue riders, over the last several years the annual average authorized ROEs in these cases was typically at least 70 basis points higher than in general rate cases, driven by the ROE premiums authorized in Virginia. Limited issue rider cases in which an ROE is determined have had extremely limited use in the gas industry.

Comparing electric vertically integrated cases versus delivery only proceedings, RRA finds that the annual average authorized ROEs in vertically integrated cases typically are from roughly 40 to 70 basis points higher than in delivery only cases, arguably reflecting the increased risk associated with generation assets.

The simple mean is utilized for the return averages. In addition, the average equity returns indicated in this report reflect the cases decided in the specified time periods and are not necessarily representative of the returns actually earned by utilities industry wide.

As a result of electric industry restructuring, certain states unbundled electric rates and implemented retail competition for generation. Commissions in those states now have jurisdiction only over the revenue requirement and return parameters for delivery operations, which we footnote in our chronology


MPSC Case No.:U-18424Exhibit AB-6Witness: Billie S. LaConteDate: February 2018 Page 2 of 13



beginning on page 9, thus complicating historical data comparability. From 2008 through 2015, interest rates declined significantly, and average authorized ROEs have declined modestly. Also, limited issue rider proceedings that allow utilities to recover certain costs outside of a general rate case and typically incorporate previously determined return parameters have been increasingly utilized.

The table on page 5 shows the average ROE authorized in major electric and gas rate decisions annually since 1990, and by quarter since 2014, followed by the number of observations in each period. The tables on page 6 indicate the composite electric and gas industry data for all major cases summarized annually since 2003 and by quarter for the past eight quarters. The individual electric and gas cases decided in 2017 are listed on pages 9-13, with the decision date shown first, followed by the company name, the abbreviation for the state issuing the decision, the authorized rate of return, or ROR, ROE, and percentage of common equity in the adopted capital structure. Next, we indicate the month and year in which the adopted test year ended, whether the commission utilized an average or a year end rate base, and the amount of the permanent rate change authorized. The dollar amounts represent the permanent rate change ordered at the time decisions were rendered. Fuel adjustment clause rate changes are not reflected in this study.

The table and graph below track the average and median equity return authorized for all electric and gas rate cases combined, by year, for the last 28 years. As the table indicates, since 1990 authorized ROEs have generally trended downward, reflecting the significant decline in interest rates and capital costs that has occurred over this time frame. The combined average and median equity returns authorized for electric and gas utilities in each of the years 1990 through 2017, and the number of observations for each year are presented in the accompanying tables.

1990 12.69 12.75 71 2004 10.72 10.50 43

1991 12.50 12.50 73 2005 10.46 10.40 50

1992 12.06 12.00 73 2006 10.35 10.25 41

1993 11.40 11.50 68 2007 10.26 10.20 73

1994 11.23 11.22 52 2008 10.40 10.39 69

1995 11.53 11.38 41 2009 10.39 10.43 70

1996 11.26 11.25 35 2010 10.28 10.22 100

1997 11.31 11.28 22 2011 10.19 10.10 58

1998 11.64 11.65 20 2012 10.09 10.00 93

1999 10.73 10.70 12 2013 9.92 9.80 70

2000 11.44 11.25 22 2014 9.86 9.78 64

2001 11.04 11.00 20 2015 9.76 9.65 46

2002 11.19 11.16 33 2016 9.68 9.60 68

2003 10.98 10.75 45 2017 9.73 9.60 77

Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence.

Composite electric and gas annual authorized ROEs: 1990 — 2017

YearAverage ROE (%)

Median ROE (%)

No. of Observations Year

Average ROE (%)

Median ROE (%)

No. of Observations


MPSC Case No.: U-18424Exhibit AB-6Witness: Billie S. LaConteDate: February 2018Page 3 of 13



Please Note: In an effort to align data presented in this report with data available in S&P Global Market Intelligence's online data base, earlier historical data provided in previous reports may not match historical data in this report due to certain differences in presentation, including the treatment of cases that were withdrawn or dismissed.

©2018, Regulatory Research Associates, Inc., an offering of S&P Global Market Intelligence. All Rights Reserved. Confidential Subject Matter. WARNING! This report contains copyrighted subject matter and confidential information owned solely by Regulatory Research Associates, Inc. ("RRA"). Reproduction, distribution or use of this report in violation of this license constitutes copyright infringement in violation of federal and state law. RRA hereby provides consent to use the "email this story" feature to redistribute articles within the subscriber's company. Although the information in this report has been obtained from sources that RRA believes to be reliable, RRA does not guarantee its accuracy.


MPSC Case No.: U-18424Exhibit AB-6Witness: Billie S. LaConteDate: February 2018Page 4 of 13



ROEs authorized January 1990 - December 2017Electric utilities Gas utilities

Year Period

1990 Full year 12.70 12.77 38 12.68 12.75 331991 Full year 12.54 12.50 42 12.45 12.50 31

1992 Full year 12.09 12.00 45 12.02 12.00 28

1993 Full year 11.46 11.50 28 11.37 11.50 40

1994 Full year 11.21 11.13 28 11.24 11.27 24

1995 Full year 11.58 11.45 28 11.44 11.30 13

1996 Full year 11.40 11.25 18 11.12 11.25 17

1997 Full year 11.33 11.58 10 11.30 11.25 12

1998 Full year 11.77 12.00 10 11.51 11.40 10

1999 Full year 10.72 10.75 6 10.74 10.65 6

2000 Full year 11.58 11.50 9 11.34 11.16 13

2001 Full year 11.07 11.00 15 10.96 11.00 5

2002 Full year 11.21 11.28 14 11.17 11.00 19

2003 Full year 10.96 10.75 20 10.99 11.00 25

2004 Full year 10.81 10.70 21 10.63 10.50 22

2005 Full year 10.51 10.35 24 10.41 10.40 26

2006 Full year 10.32 10.23 26 10.40 10.50 15

2007 Full year 10.30 10.20 38 10.22 10.20 35

2008 Full year 10.41 10.30 37 10.39 10.45 32

2009 Full year 10.52 10.50 40 10.22 10.26 30

2010 Full year 10.37 10.30 61 10.15 10.10 39

2011 Full year 10.29 10.17 42 9.92 10.03 16

2012 Full year 10.17 10.08 58 9.94 10.00 35

2013 Full year 10.03 9.95 49 9.68 9.72 21

1st quarter 10.23 9.86 8 9.54 9.60 6

2nd quarter 9.83 9.70 5 9.84 9.95 8

3rd quarter 9.87 9.78 12 9.45 9.33 6

4th quarter 9.78 9.80 13 10.28 10.20 6

2014 Full year 9.91 9.78 38 9.78 9.78 26

1st quarter 10.37 9.83 9 9.47 9.05 3

2nd quarter 9.73 9.60 7 9.43 9.50 3

3rd quarter 9.40 9.40 2 9.75 9.75 1

4th quarter 9.62 9.55 12 9.68 9.75 9

2015 Full year 9.85 9.65 30 9.60 9.68 16

1st quarter 10.29 10.50 9 9.48 9.50 6

2nd quarter 9.60 9.60 7 9.42 9.52 6

3rd quarter 9.76 9.80 8 9.47 9.50 4

4th quarter 9.57 9.58 18 9.68 9.73 10

2016 Full year 9.77 9.75 42 9.54 9.50 26

1st quarter 9.87 9.60 15 9.60 9.25 3

2nd quarter 9.63 9.50 14 9.47 9.60 7

3rd quarter 9.66 9.60 5 10.14 9.90 6

4th quarter 9.73 9.60 19 9.68 9.55 8

2017 Full year 9.74 9.60 53 9.72 9.60 24

Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence

Average ROE (%)

Median ROE (%)

Average ROE (%)

Median ROE (%)

Number of observations



MPSC Case No.: U-18424Exhibit AB-6Witness: Billie S. LaConteDate: February 2018 Page 5 of 13



Period ROR (%) ROE (%) $M

2003 Full year 9.08 18 10.96 20 49.32 18 312.9 21

2004 Full year 8.71 20 10.81 21 46.96 19 1,806.3 29

2005 Full year 8.44 23 10.51 24 47.34 23 936.1 31

2006 Full year 8.32 26 10.32 26 48.54 25 1,318.1 39

2007 Full year 8.18 37 10.30 38 47.88 36 1,405.7 43

2008 Full year 8.21 39 10.41 37 47.94 36 2,823.2 44

2009 Full year 8.24 40 10.52 40 48.57 39 4,191.7 58

2010 Full year 8.01 62 10.37 61 48.63 57 4,921.9 78

2011 Full year 8.00 43 10.29 42 48.26 42 2,595.1 56

2012 Full year 7.95 51 10.17 58 50.69 52 3,080.7 69

2013 Full year 7.66 45 10.03 49 49.25 43 3,328.6 61

2014 Full year 7.60 32 9.91 38 50.28 35 2,053.7 51

2015 Full year 7.38 35 9.85 30 49.54 30 1,891.5 52

1st quarter 7.03 9 10.29 9 46.06 9 311.2 12

2nd quarter 7.42 7 9.60 7 49.91 7 117.7 9

3rd quarter 7.23 8 9.76 8 49.11 8 499.3 13

4th quarter 7.38 17 9.57 18 49.93 17 1,403.9 23

2016 Full year 7.28 41 9.77 42 48.91 41 2,332.1 57

1st quarter 6.97 15 9.87 15 47.95 15 1,015.8 23

2nd quarter 7.11 9 9.63 14 48.77 9 597.0 19

3rd quarter 7.43 5 9.66 5 49.63 5 558.6 10

4th quarter 7.32 19 9.73 19 49.51 19 593.8 23

2017 Full year 7.18 48 9.74 53 48.74 48 2,765.2 75

Period ROR (%) ROE (%) $M

2003 Full year 8.75 22 10.99 25 49.93 22 260.1 30

2004 Full year 8.34 21 10.59 20 45.90 20 303.5 31

2005 Full year 8.25 29 10.46 26 48.66 24 458.4 34

2006 Full year 8.44 17 10.40 15 47.24 16 392.5 23

2007 Full year 8.11 31 10.22 35 48.47 28 645.3 43

2008 Full year 8.49 33 10.39 32 50.35 32 700.0 40

2009 Full year 8.15 29 10.22 30 48.49 29 438.6 36

2010 Full year 7.99 40 10.15 39 48.70 40 776.5 50

2011 Full year 8.09 18 9.92 16 52.49 14 367.0 31

2012 Full year 7.98 30 9.94 35 51.13 32 264.0 41

2013 Full year 7.43 21 9.68 21 50.60 20 498.7 39

2014 Full year 7.65 27 9.78 26 51.11 28 529.2 48

2015 Full year 7.34 16 9.60 16 49.93 16 494.1 40

1st quarter 7.12 6 9.48 6 50.83 6 120.2 11

2nd quarter 7.38 6 9.42 6 50.01 6 276.3 16

3rd quarter 6.59 5 9.47 4 48.44 4 106.3 8

4th quarter 7.11 11 9.68 10 50.27 10 761.1 24

2016 Full year 7.08 28 9.54 26 50.06 26 1,263.9 59

1st quarter 7.20 2 9.60 3 51.57 3 71.0 9

2nd quarter 7.27 5 9.47 7 49.15 5 85.2 13

3rd quarter 7.07 8 10.14 6 46.58 7 128.6 17

4th quarter 7.43 9 9.68 8 52.30 9 130.8 15

2017 Full year 7.26 24 9.72 24 49.88 24 415.6 54


Electric utilities — summary table

Gas utilities — summary table








Capital structure

Capital structure



MPSC Case No.: U-18424Exhibit: AB-6Witness: Billie S. LaConteDate: Februrary 2018 Page 6 of 13



Settled cases Fully litigated cases

Year

2006 10.32 10.23 26 10.26 10.25 11 10.37 10.12 15

2007 10.30 10.20 38 10.42 10.33 14 10.23 10.15 24

2008 10.41 10.30 37 10.43 10.25 17 10.39 10.54 20

2009 10.52 10.50 40 10.64 10.62 16 10.45 10.50 24

2010 10.37 10.30 61 10.39 10.30 34 10.35 10.10 27

2011 10.29 10.17 42 10.12 10.07 16 10.39 10.25 26

2012 10.17 10.08 58 10.06 10.00 29 10.28 10.25 29

2013 10.03 9.95 49 10.12 9.98 32 9.85 9.75 17

2014 9.91 9.78 38 9.73 9.75 17 10.05 9.83 21

2015 9.85 9.65 30 10.07 9.72 14 9.66 9.62 16

2016 9.77 9.75 42 9.80 9.85 17 9.74 9.60 25

2017 9.74 9.60 53 9.75 9.60 29 9.73 9.55 24

Year

2006 10.32 10.23 26 10.34 10.25 25 9.80 9.80 1

2007 10.30 10.20 38 10.32 10.23 36 9.90 9.90 1

2008 10.41 10.30 37 10.37 10.30 35 11.11 11.11 2

2009 10.52 10.50 40 10.52 10.50 38 10.55 10.55 2

2010 10.37 10.30 61 10.29 10.26 58 11.87 12.30 32011 10.29 10.17 42 10.19 10.14 40 12.30 12.30 2

2012 10.17 10.08 58 10.02 10.00 51 11.57 11.40 6

2013 10.03 9.95 49 9.82 9.82 40 11.34 11.40 7

2014 9.91 9.78 38 9.76 9.75 32 10.96 11.00 5

2015 9.85 9.65 30 9.60 9.53 23 10.87 11.00 6

2016 9.77 9.75 42 9.60 9.60 32 10.31 10.55 10

2017 9.74 9.60 53 9.68 9.60 42 10.01 9.95 10

Year

2006 10.32 10.23 26 10.63 10.54 15 9.91 10.03 10

2007 10.30 10.20 38 10.50 10.45 26 9.86 9.98 11

2008 10.41 10.30 37 10.48 10.47 26 10.04 10.25 9

2009 10.52 10.50 40 10.66 10.66 28 10.15 10.30 10

2010 10.37 10.30 61 10.42 10.40 41 9.98 10.00 17

2011 10.29 10.17 42 10.33 10.20 28 9.85 10.00 12

2012 10.17 10.08 58 10.10 10.20 39 9.73 9.73 13

2013 10.03 9.95 49 9.95 10.00 31 9.41 9.36 11

2014 9.91 9.78 38 9.94 9.90 19 9.50 9.55 14

2015 9.85 9.65 30 9.75 9.70 17 9.23 9.07 7

2016 9.77 9.75 42 9.77 9.78 20 9.31 9.33 12

2017 9.74 9.60 53 9.80 9.65 28 9.43 9.55 14


Electric authorized ROEs: 2006 — 2017 Settled versus fully litigated cases

All cases

Average ROE (%)

Median ROE (%)


Average ROE (%)

Median ROE (%)


Average ROE (%)

Median ROE (%)


General rate cases versus limited issue ridersAll cases General rate cases Limited issue riders

Average ROE (%)

Median ROE (%)


Vertically integrated cases versus delivery only cases Vertically

Average ROE (%)

Median ROE (%)


Average ROE (%)

Median ROE (%)


Median ROE (%)


All cases integrated cases Delivery only cases

Average ROE (%)

Median ROE (%)


Average ROE (%)

Median ROE (%)


Average ROE (%)


MPSC Case No.:U-18424 Exhibit: AB-6 Witness: Billie S. LaConte Date: February 2018 Page 7 of 13



Settled cases Fully litigated cases

Year

2006 10.40 10.50 15 10.26 10.20 7 10.53 10.80 8

2007 10.22 10.20 35 10.24 10.18 22 10.20 10.40 13

2008 10.39 10.45 32 10.34 10.28 20 10.47 10.68 12

2009 10.22 10.26 30 10.43 10.40 13 10.05 10.15 17

2010 10.15 10.10 39 10.30 10.15 12 10.08 10.10 27

2011 9.92 10.03 16 10.08 10.08 8 9.76 9.80 8

2012 9.94 10.00 35 9.99 10.00 14 9.92 9.90 21

2013 9.68 9.72 21 9.80 9.80 9 9.59 9.60 12

2014 9.78 9.78 26 9.51 9.50 11 9.98 10.10 15

2015 9.60 9.68 16 9.60 9.60 11 9.58 9.80 5

2016 9.54 9.50 26 9.50 9.50 16 9.61 9.58 10

2017 9.72 9.60 24 9.68 9.60 17 9.89 9.50 7

General rate cases

Year

2006 10.40 10.50 15 10.40 10.50 15 — — 0

2007 10.22 10.20 35 10.22 10.20 35 — — 0

2008 10.39 10.45 32 10.39 10.45 32 — — 0

2009 10.22 10.26 30 10.22 10.26 30 — — 0

2010 10.15 10.10 39 10.15 10.10 39 — — 02011 9.92 10.03 16 9.91 10.05 15 10.00 10.00 1

2012 9.94 10.00 35 9.93 10.00 34 10.40 10.40 1

2013 9.68 9.72 21 9.68 9.72 21 — — 02014 9.78 9.78 26 9.78 9.78 26 — — 0

2015 9.60 9.68 16 9.60 9.68 16 — — 0

2016 9.54 9.50 26 9.53 9.50 25 9.70 9.70 1

2017 9.72 9.60 24 9.72 9.60 24 — — 0


Gas average authorized ROEs: 2006 — 2017

Settled versus fully litigated casesAll cases

Average ROE (%)

Median ROE (%)


Average ROE (%)

Median ROE (%)


Average ROE (%)

Median ROE (%)

Number of Observations

General rate cases versus limited issue ridersAll cases Limited issue riders

Average ROE (%)

Median ROE (%)


Average ROE (%)

Median ROE (%)


Average ROE (%)

Median ROE (%)






Electric utility decisions

Date Company State ROR

(%) ROE (%)

Common equity as

% of capital

Test year

Rate base

Amt.($M) Footnotes

1/10/17 Empire District Electric Company KS — — — — — — (1)

1/12/17 Electric Transmission Texas TX 6.39 9.60 40.00 12/16 Year-end -46.2 (Tr,B)

1/17/17 Cross Texas Transmission TX — — — — — -6.5 (Tr,B)

1/18/17 MDU Resources Group, Inc. WY 7.25 9.45 50.99 12/15 Year-end 2.7 (B)

1/19/17 Metropolitan Edison Company PA — — — 12/17 — 90.5 (D,B)

1/19/17 Pennsylvania Electric Company PA — — — 12/17 — 94.6 (D,B)

1/19/17 Pennsylvania Power Company PA — — — 12/17 — 27.5 (D,B)

1/19/17 West Penn Power Company PA — — — 12/17 — 60.6 (D,B)

1/24/17 Consolidated Edison Co. of NY NY 6.82 9.00 48.00 12/17 Average 194.5 (D,B)

1/25/17 Northern Indiana Public Service Co. IN — — — 4/16 Year-end 1.9 (LIR,B,2)

1/26/17 Southwestern Public Service Co. TX — — — 9/15 Year-end 35.2 (B)

1/31/17 DTE Electric Company MI 5.55 10.10 37.49 7/17 Average 184.3 (I,*)

2/15/17 Delmarva Power & Light Company MD 6.74 9.60 49.10 3/16 Average 38.3 (D)

2/22/17 Rockland Electric Company NJ 7.47 9.60 49.70 12/16 Year-end 1.7 (D,B)

2/24/17 Indianapolis Power & Light Company IN — — — — — — (1)

2/24/17 Tucson Electric Power Company AZ 7.04 9.75 50.03 6/15 Year-end 81.5 (B)

2/27/17 Virginia Electric and Power Company VA 7.73 11.40 49.49 3/18 Average -2.4 (LIR,3)

2/27/17 Virginia Electric and Power Company VA 6.74 9.40 49.49 3/18 Average 41.4 (LIR,4)




2/28/17 Consumers Energy Company MI 5.94 10.10 40.75 8/17 Average 113.3 (I,*)

3/2/17 Otter Tail Power Company MN 7.51 9.41 52.50 12/16 Average 12.3 (I)

3/8/17 Union Electric Company MO — — — 3/16 — 92.0 (B)

3/20/17 Oklahoma Gas and Electric Co. OK 7.69 9.50 53.31 6/15 Year-end 8.8 (I)

2017 1st quarter: averages/total 6.97 9.87 47.95 1,015.8

Observations 15 15 15 25

4/4/17 Gulf Power Company FL — 10.25 — 12/17 — 62.0 (B)

4/12/17 Liberty Utilities (Granite State Electric) NH 7.64 9.40 50.00 12/15 — 3.8 (D,IB,Z)

4/19/17 Southwestern Public Service Company NM — — — — — 0.0 (8)

4/20/17 Unitil Energy Systems, Inc. NH 8.34 9.50 50.97 12/15 — 4.1 (D,IB,Z)

5/3/17 Kansas City Power & Light Company MO 7.43 9.50 49.20 12/15 Year-end 32.5

5/11/17 Pacific Gas and Electric Company CA — — — 12/17 Average 91.0 (B,Z)

5/11/17 Appalachian Power Company VA — — — 6/18 Average 4.7 (B,LIR,9)

5/11/17 Northern States Power Company - MN MN 7.08 9.20 52.50 12/19 Average 244.7 (B,I,Z)

5/18/17 Oklahoma Gas and Electric Company AR 5.42 9.50 36.38 6/16 Year-end 7.1 (B,*)

5/23/17 Delmarva Power & Light Company DE — 9.70 — 12/15 — 31.5 (D,B,I)

5/31/17 Idaho Power Co. ID — 9.50 — — — 13.3 (B,LIR)


MPSC Case No.: U-18424Exhibit AB-6Witness: Billie S. LaConte Date: February 2018 Page 9 of 13





(%) ROE (%)

Common equity as

% of capital

Test year

Rate base

Amt.($M) Footnotes

6/1/17 Virginia Electric and Power Company VA 6.74 9.40 49.49 8/18 — -12.8 (LIR,10)

6/6/17 Kansas City Power & Light Company KS — — — 6/14 — -3.6 (B,11)

6/8/17 Westar Energy, Inc. KS — — — 9/14 — 16.4 (B,11)

6/16/17 MDU Resources Group, Inc. ND 7.36 9.65 51.40 12/17 Average 7.5 (B,I)

6/22/17 Kentucky Utilities Company KY — 9.70 — — — 51.6 (B,R)

6/22/17 Louisville Gas and Electric Company KY — 9.70 — — — 57.1 (B,R)



2017 2nd quarter: averages/total 7.11 9.63 48.77 597.0


7/17/17 Appalachian Power Company VA — — — — — 0.0 (LIR,14)

7/24/17 Potomac Electric Power Company DC 7.46 9.50 49.14 3/16 Average 36.9 (D)

8/4/17 Maui Electric Company, Limited HI — — — — — 0.0

8/10/17 Wisconsin Electric Power Company WI — — — 12/19 — 0.0 (B,Z)

8/10/17 Wisconsin Public Service Corporation WI — — — 12/19 — 0.0 (B,Z)

8/15/17 Arizona Public Service Company AZ 7.85 10.00 55.80 12/15 Year-end 362.6 (B)


9/22/17 Atlantic City Electric Company NJ 7.60 9.60 50.47 7/17 Year-end 43.0 (B,D)

9/28/17 Sharyland Utilities, L.P. TX — — — — — -3.0 (B,D)

9/28/17 Oncor Electric Delivery Company LLC TX 7.44 9.80 42.50 12/16 Year-end 118.1 (B,D)

2017 3rd quarter: averages/total 7.43 9.66 49.63 558.6


10/20/17 Potomac Electric Power Company MD 7.43 9.50 50.15 4/17 Average 32.4 (D,R)

10/25/17 Duke Energy Florida, LLC FL — — — — — 200.0 (B,Z)

10/26/17 San Diego Gas & Electric Co. CA 7.55 10.20 52.00 12/18 — -13.1 (B,16)

10/26/17 Southern California Edison Company CA 7.61 10.30 48.00 12/18 — -73.0 (B,16)

10/26/17 Pacific Gas and Electric Company CA 7.69 10.25 52.00 12/18 — -120.0 (B,16,17)

10/31/17 Northern Indiana Public Service Company IN — — — 4/17 — 14.6 (LIR,18)

11/6/17 Tampa Electric Company FL — 10.25 — — — 0.0 (B,Z,19)

11/15/17 Alaska Electric Light and Power Company AK 8.91 11.95 58.18 12/15 Average 3.4 (B, I)

11/30/17 NSTAR Electric Company MA 7.33 10.00 53.34 6/16 Year-end 12.2 (D,Z,20)

11/30/17 Western Massachusetts Electric Company MA 7.26 10.00 54.51 6/16 Year-end 24.8 (D,Z,20)

12/5/17 Puget Sound Energy, Inc. WA 7.60 9.50 48.50 9/16 Average 106.4 (B)

12/6/17 Ameren Illinois Company IL 7.04 8.40 50.00 12/16 Year-end -16.4 (D)

12/6/17 Commonwealth Edison Company IL 6.47 8.40 45.89 12/16 Year-end 99.2 (D)

12/7/17 Northern States Power Company - WI WI 7.56 9.80 51.45 12/18 Average 9.4

12/13/17 Entergy Arkansas, Inc. AR 4.64 — 31.62 12/18 Average 113.4 (B,*)

12/14/17 Southwestern Electric Power Company TX 7.18 9.60 48.46 6/16 Year-end 86.9 (I)

12/14/17 El Paso Electric Company TX 7.73 9.65 48.35 9/16 — 14.5 (B,I)

12/18/17 Portland General Electric Company OR 7.35 9.50 50.00 12/18 Year-end 15.9 (B)

12/20/17 Public Service Company of New Mexico NM 7.23 9.58 49.61 12/18 Average 62.3 (B,R,Z)







(%) ROE (%)

Common equity as

% of capital

Test year

Rate base

Amt.($M) Footnotes

12/20/17 Southern Indiana Gas and Electric Company, Inc.

IN — — — 4/17 Year-end 1.6 (LIR)

12/21/17 Green Mountain Power Corporation VT 6.87 9.10 48.60 12/16 Average 31.9 (B)

12/28/17 Avista Corporation ID 7.61 9.50 50.00 12/16 Year-end 17.4 (B,Z)

12/29/17 Nevada Power Company NV 7.95 9.40 49.99 12/16 Year-end -30.0

2017 4th quarter: averages/total 7.32 9.73 49.51 593.84


2017 Full year: averages/total 7.18 9.74 48.74

2,765.2

Observations 48.00 53.00 48.00 77 Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence

Gas utility decisions


(%) ROE (%)

Common equity as

% of capital

Test year

Rate base

Amt. ($M) Footnotes

1/18/17 Missouri Gas Energy MO — — — 8/16 — 3.2 (LIR,21)

1/18/17 Spire Missouri MO — — — 8/16 — 4.5 (LIR,21)

1/24/17 Consolidated Edison Co. of NY NY 6.82 9.00 48.00 12/17 Average -5.3 (B)

1/25/17 Southern Indiana Gas and Electric Company, Inc. IN — — — 6/16 Year-end

1.9 (LIR)

1/25/17 Indiana Gas Company, Inc. IN — — — 6/16 Year-end 8.5 (LIR)

2/9/17 Atmos Energy Corporation KS — — — — 0.8 (LIR,22)

2/21/17 Atlanta Gas Light Company GA — 10.55 51.00 — 20.4 (B,23)

3/1/17 Washington Gas Light Company DC 7.57 9.25 55.70 9/15 Average 8.5

3/17/17 Columbia Gas of Virginia, Inc. VA — — — 12/15 — 28.5 (B,I)

2017 1st quarter: averages/total 7.20 9.60 51.57 71.0


4/11/17 Southwest Gas Corporation AZ 7.42 9.50 51.70 11/15 Year-end 16.0 (B)

4/20/17 National Fuel Gas Distribution Corp. NY 6.92 8.70 42.90 3/18 Average 5.9

4/26/17 Spire Missouri MO — — — 2/17 — 3.0 (B,LIR,21)

4/26/17 Missouri Gas Energy MO — — — 2/17 — 3.0 (B,LIR,21)

4/27/17 Delta Natural Gas Company, Inc. KY — — — 12/16 Year-end 1.8 (LIR,24)

4/28/17 Intermountain Gas Company ID 7.30 9.50 50.00 12/16 Average 5.3

5/11/17 Pacific Gas and Electric Company CA — — — 12/17 Average -3.0 (B,Z)

5/23/17 Black Hills Kansas Gas Utility Company KS — — — 12/16 Year-end 0.6 (LIR)

5/23/17 CenterPoint Energy Resources Corp. TX 8.02 9.60 55.15 6/16 Year-end 16.5 (B)

6/6/17 Delmarva Power & Light Company DE — 9.70 — 12/15 — 4.9 (B,I)

6/22/17 Louisville Gas and Electric Company KY — 9.70 — — — 6.8 (B,R)

6/28/17 Northern Indiana Public Service Company IN — — — 12/16 Year-end 11.1 (LIR)

6/30/17 Pivotal Utility Holdings, Inc. NJ 6.71 9.60 46.00 3/17 Year-end 13.3 (B)

2017 2nd quarter: averages/total 7.27 9.47 49.15 85.2






Gas utility decisions


(%) ROE (%)

Common equity as

% of capital

Test year

Rate base

Amt. ($M) Footnotes

7/21/17 NorthWestern Corporation MT 6.96 9.55 46.79 12/15 Average 5.1 (B,) 7/26/17 Southern Indiana Gas and Electric

Company, Inc. IN — — — 12/16 Year-end 3.4 LIR

7/26/17 Indiana Gas Company, Inc. IN — — — 12/16 Year-end 9.2 LIR

7/31/17 Consumers Energy Company MI 5.97 10.10 41.27 12/17 Average 29.2 (I,*)

8/9/17 Oklahoma Natural Gas Company OK — — — 12/16 — 0.0 (B,25)

8/10/17 Wisconsin Electric Power Company WI — — — 12/19 — 0.0 (B,Z)

8/10/17 Wisconsin Gas LLC WI — — — 12/19 — 0.0 (B,Z)

8/10/17 Wisconsin Public Service Corporation WI — — — 12/19 — 0.0 (B,Z)

8/21/17 Virginia Natural Gas, Inc. VA — — — 8/18 Average 2.9 (LIR,26)

8/31/17 UGI Penn Natural Gas, Inc. PA — — — 9/18 — 11.3 (B)

9/6/17 CenterPoint Energy Resources Corp. AR 4.58 — 31.02 9/18 Year-end 7.6 (*,B)

9/8/17 Washington Gas Light Company VA — — — 11/17 — 34.0 (I,B)

9/13/17 Avista Corporation OR 7.35 9.40 50.00 9/18 Average 3.5 (B,Z)

9/19/17 Columbia Gas of Maryland, Incorporated MD 7.35 9.70 — 4/17 — 2.4 (B)

9/22/17 ENSTAR Natural Gas Company AK 8.59 11.88 51.81 12/15 Average 5.8 (I)

9/27/17 South Carolina Electric & Gas Co. SC 8.15 — 52.16 3/17 Year-end 8.6 (M)

9/27/17 Piedmont Natural Gas Company, Inc. SC 7.60 10.20 53.00 3/17 Year-end 5.5 (B,27)

2017 3rd quarter: averages/total 7.07 10.14 46.58 128.6


10/19/17 CenterPoint Energy Resources Corp. OK — — — 12/16 Year-end 2.2

10/20/17 South Jersey Gas Company NJ 6.80 9.60 52.50 8/17 Year-end 39.5 (B)

10/26/17 San Diego Gas & Electric Co. CA 7.55 10.20 52.00 12/18 — -2.0 (B,16)

10/27/17 Atmos Energy Corporation KY — — — 9/18 Year-end 10.6 (LIR)

10/30/17 Southern California Gas Company CA 7.34 10.05 52.00 12/18 — -35.1 (B,16)

11/16/17 Kansas Gas Service Company KS — — — 6/17 Year-end 2.9 (LIR)

11/21/17 Washington Gas Light Company VA 7.35 9.50 59.63 12/18 Average 16.4

12/5/17 Puget Sound Energy, Inc. WA 7.60 9.50 48.50 9/17 Average 16.6 (B)

12/7/17 Northern States Power Company - WI WI 7.56 9.80 51.45 12/18 Average 9.9

12/13/17 Columbia Gas of Virginia, Incorporated VA — — — 12/18 — 3.2 (B,LIR)

12/13/17 Southern Connecticut Gas Company CT 7.42 9.25 52.19 12/16 Average 11.2 (B,Z)

12/21/17 Virginia Natural Gas, Inc. VA — — — 9/16 — 34.1 (B,I)

12/22/17 Columbia Gas of Kentucky, Incorporated KY 7.62 — 52.42 12/18 Year-end 4.5 (LIR)

12/28/17 Northern Indiana Public Service Company IN — — — 6/17 Year-end 14.6 (LIR)

12/28/17 Avista Corporation ID 7.61 9.50 50.00 12/16 Year-end 2.3 (B,Z)

2017 4th quarter: averages/total 7.43 9.68 52.30 130.8


2017 Averages/total 7.26 9.72 49.88 415.6




MPSC Case No.: U-18424Exhibit AB-6Witness: Billie S. LaConte Date: February 2018 Page 12 of 13



FOOTNOTES A- Average

B- Order followed stipulation or settlement by the parties. Decision particulars not necessarily precedent-setting or specifically adopted by the regulatory body.

CWIP- Construction work in progress

D- Applies to electric delivery only

DCt Date certain rate base valuation

E- Estimated

F- Return on fair value rate base

Hy- Hypothetical capital structure utilized

I- Interim rates implemented prior to the issuance of final order, normally under bond and subject to refund.

LIR Limited-issue rider proceeding

M- "Make-whole" rate change based on return on equity or overall return authorized in previous case.

R- Revised

Te- Temporary rates implemented prior to the issuance of final order.

Tr- Applies to transmission service

U- Double leverage capital structure utilized.

YE- Year-end

Z- Rate change implemented in multiple steps.

* Capital structure includes cost-free items or tax credit balances at the overall rate of return.

(1) Case withdrawn by company.

(2) Initial proceeding to establish the rates to be charged to customers under the company's transmission, distribution, and storage system improvement charge, or TDSIC, rate adjustment mechanism and reflects investments made between Jan. 1, 2016 and April 30, 2016.

(3) Proceeding determines the revenue requirement for Rider B, which is the mechanism through which the company recovers costs associated with its plan to convert the Altavista, Hopewell and Southampton Power Stations to burn biomass fuels.

(4) Proceeding determines the revenue requirement for Rider GV, which is the mechanism through which the company recovers the costs associated with the new gas fired generation facility, the Greensville County project.

(5) Represents rate decrease associated with the company's Rider R proceeding, which is the mechanism through which the company recovers the investment in the Bear Garden generating facility.

(6) This proceeding determines the revenue requirement for Rider S, which recognizes in rates the company's investment in the Virginia City Hybrid Energy Center.

(7) Increase authorized through a surcharge, Rider W, which reflects in rates investment in the Warren County Power Station.

(8) The commission rejected the company's rate case filing.

(9) Case represents the company's RAC-EE rider, under which it recovers the costs and lost revenues associated with its energy efficiency programs.

(10) Case represents the company's Rider DSM, which involves a consolidation of two riders related to the company's costs and investments in demand-side management and energy conservation programs.

(11) Represents an "abbreviated" rate case.

(12) Case involves Rider US-2, which pertains to the company's investment in three new solar generation facilities with a total capacity of 56 MW.

(13) Case involves Rider BW, which relates to the company's investment in the Brunswick generating plant, which achieved commercial operation on 4/25/16.

(14) Commission rejected the company's request for an accelerated vegetation management program and an associated rate adjustment mechanism.

(15) Case involves Rider U, which pertains to the company's investment in projects to underground certain "at risk" distribution facilities.

(16) Represents a company compliance filing establishing cost of capital parameters for 2018.

(17) Rate decrease amounts represent combined electric and gas, as presented by the company.

(18) Second proceeding to establish the rates to be charged to customers under the company's transmission, distribution and storage system improvement charge, or TDSIC, rate adjustment mechanism, and reflects investments made between May 1, 2016, and April 30, 2017.

(19) Subject to certain adjustment provisions, the company's authorized ROE is to remain within a range of 9.25% to 11.25%, with a midpoint of 10.25%.

(20) A five-year performance-based regulation plan was also adopted.

(21) Case involves the company's infrastructure system replacement surcharge, or ISRS, rider.

(22) Case involves the company's gas system reliability surcharge, or GSRS, rider.

(23) In this proceeding, the commission adopted an alternative rate plan and authorized the first rate change,

(24) Case involves the company's pipe replacement program rider.

(25) Case involves the company's performance based ratemaking plan.

(26) Case involves the company's Steps to Advance Virginia Energy rider.

(27) Modified "make whole" rate change authorized.



MPSC Case No.: U-18424

Exhibit :AB-7

Witness: Billie S. LaConte

Date: February 2018

Page 1 of 1

Ratio Cost Wtd. Cost Pretax Ratio Cost Wtd. Cost Pretax(1) (2) (3) (4) (5) (6) (7) (8)

Line Description Description

1 Long-Term Debt 36.70% 4.68% 1.718% 1.72% Long-Term Debt 36.70% 4.68% 1.718% 1.7176%

2 Preferred Equity 0.23% 4.50% 0.010% 0.02% Preferred Equity 0.23% 4.50% 0.010% 0.0170%

3 Common Equity 40.80% 10.50% 4.284% 7.02% Common Equity 40.80% 9.72% 3.966% 6.4947%

4 Customer Deposits 0.15% 7.00% 0.011% 0.01% Customer Deposits 0.15% 7.00% 0.011% 0.0105%

5 Other Interest Bearing Accounts 0.10% 4.00% 0.004% 0.01% Other Interest Bearing Accounts 0.10% 4.00% 0.004% 0.0040%

6 Short-Term Debt 1.12% 3.53% 0.040% 0.04% Short-Term Debt 1.12% 3.53% 0.040% 0.0395%

7 Deferred FIT 20.29% 0.00% 0.000% 0.00% Deferred FIT 20.29% 0.00% 0.000% 0.0000%

8 Investment Tax Credit Investment Tax Credit 0.000%

9 Long-Term Debt 0.28% 4.68% 0.013% 0.01% Long-Term Debt 0.28% 4.68% 0.013% 0.0131%

10 Preferred Equity 0.00% 4.50% 0.000% 0.00% Preferred Equity 0.00% 4.50% 0.000% 0.0000%

11 Common Equity 0.33% 10.50% 0.035% 0.06% Common Equity 0.33% 9.72% 0.032% 0.0525%

12 Total Capitalization 100.00% 6.114% 8.88% Total Capitalization 100.00% 5.793% 8.3490%

13 Revenue Conversion Factor 1.6377

14 Consumer's Energy Test Year Rate Base ($000) $5,468,043 Impact of change in ROE -$28,868

Sources:

Overall Rate of Return Summary

for the Test Year Ended June 30, 2019

Exhibit A-14 (AJD-1)

Schedule D-1

Proposed ROE for the Test Year Ending June 30, 2019 Recommended ROE for Test Year Ending June 30, 2019

CONSUMERS ENERGY COMPANYRecommended ROE and Rate of Return


Exhibit :AB-8


Date: February 2018

Page 1 of 1

Line Summary Description Total Residential Rate GS-1 Rate GS-2 Rate GS-3 Rate ST Rate LT Rate XLT Rate XXLT

1 Service Revenue $1,610,042 $1,180,421 $162,198 $157,600 $38,843 $24,143 $17,110 $22,346 $7,3822 Other Revenue $89,978 $63,372 $9,827 $11,866 $2,476 $629 $539 $955 $3133 Total Revenue $1,700,020 $1,243,793 $172,026 $169,466 $41,318 $24,772 $17,649 $23,300 $7,696

4 Expenses:5 Cost of Gas Sold (COGS) $681,507 $490,657 $80,237 $83,995 $26,618 $0 $0 $0 $06 O & M Expense $351,015 $274,709 $28,016 $21,981 $4,114 $6,863 $5,072 $7,707 $2,5527 Depreciation & Amortization Expense $263,142 $191,577 $22,498 $22,325 $4,306 $6,734 $5,094 $7,958 $2,6508 Lost and Unaccounted for (LAUF) Gas $9,614 $6,922 $1,092 $1,326 $275 $0 $0 $0 $09 Taxes $172,127 $123,952 $15,855 $15,626 $2,680 $4,686 $3,373 $4,474 $1,47910 Company Use $5,453 $3,926 $619 $752 $156 $0 $0 $0 $011 Total Expenses $1,482,858 $1,091,743 $148,319 $146,005 $38,149 $18,284 $13,539 $20,139 $6,681

12 Net Operating Income $217,162 $152,050 $23,707 $23,461 $3,170 $6,489 $4,110 $3,161 $1,014

13 Test Year AFUDC $8,260 $5,357 $771 $928 $194 $266 $224 $392 $129

14 Adjusted Net Operating Income $225,422 $157,406 $24,478 $24,389 $3,364 $6,755 $4,334 $3,553 $1,143

15 Total Rate Base 5,468,043$ 3,841,028$ 480,037$ 510,334$ 102,704$ 152,283$ 119,973$ 196,935$ 64,748$

16 Return on Rate Base @ 6.11% $334,231 $234,781 $29,342 $31,194 $6,278 $9,308 $7,333 $12,038 $3,958

17 Income Deficiency/(Sufficiency) $108,809 $77,374 $4,864 $6,805 $2,914 $2,553 $2,999 $8,484 $2,815

18 Revenue Deficiency/(Sufficiency) $178,193 $126,714 $7,966 $11,144 $4,772 $4,181 $4,912 $13,895 $4,610

19 Rev Requirement/Total Cost of Service $1,878,214 $1,370,507 $179,992 $180,610 $46,090 $28,954 $22,560 $37,195 $12,30620 Less: Cost of Gas Sold (Test Yr) $681,507 $490,657 $80,237 $83,995 $26,618 $0 $0 $0 $021 Less: Miscellaneous Revenue (TY) $89,978 $63,372 $9,827 $11,866 $2,476 $629 $539 $955 $31322 Proposed Rate Design Revenue $1,106,729 $816,478 $89,927 $84,749 $16,997 $28,324 $22,021 $36,240 $11,992

23 Transmission Related Cost $224,606 $136,615 $21,284 $27,072 $5,931 $8,338 $7,262 $13,606 $4,49724 Storage Related Cost $156,372 $99,274 $15,723 $19,936 $4,526 $4,151 $3,596 $7,018 $2,14725 Distribution Related Cost $725,751 $580,588 $52,920 $37,741 $6,539 $15,835 $11,163 $15,616 $5,34926 Total $1,106,729 $816,478 $89,927 $84,749 $16,997 $28,324 $22,021 $36,240 $11,992

27 Decrease return, allocate by rate base $28,868 $20,279 $2,534 $2,694 $542 $804 $633 $1,040 $34228 Mcf Thruput 302,215,970 158,739,927 25,065,889 32,387,576 7,306,464 18,657,038 17,697,506 31,318,792 11,042,77729 Customer Count 1,777,539 1,644,709 118,383 11,876 381 1,409 644 135 230 Cost per Customer of decrease in ROE $12.33 $21.41 $226.87 $1,423.16 $570.60 $983.53 $7,701.59 $170,918.93

Source:

Exhibit A-16 (LFS-2), Schedule F-1a, page 1 of 6.

CONSUMERS ENERGY COMPANYCost per Customer Due to Overstated ROE


Exhibit :AB-9


Date: February 2018

Page 1 of 1

Test Year 1926-2016 Test YearCurrent Risk-Free Risk Premium CAPM

Line Company Ticker Beta (B) Rate (Rf) (Rp) ROE(1) (2) (3) (4)

c.2 + c.3 * c.1

1 Atmos Energy Corporation ATO 0.70 3.96% 6.93% 8.81%2 Nisource, Incorporated NI 0.65 3.96% 6.93% 8.47%3 Northwest Natural Gas Company NWN 0.65 3.96% 6.93% 8.47%4 ONE Gas, Inc. OGS 0.70 3.96% 6.93% 8.81%5 Southwest Gas Holdings, Inc. SWX 0.75 3.96% 6.93% 9.16%6 Spire Inc. SR 0.70 3.96% 6.93% 8.81%

7 Average 0.69 8.76%8 Minimum 0.65 8.47%9 Maximum 0.75 9.16%

Sources:Column 1: Beta per the Value Line Investment Survey (Gas Utilities as of June 2, 2017)Column 2: Average of Global Insight U.S. Economic Outlook (Jun 2017) & Blue Chip (June 1, 2017).Columns 3: Exhibit A-14 (SM-1), Schedule D-5, page 10, line 51.

Capital Asset Pricing ModelCONSUMERS ENERGY COMPANY


Exhibit :AB-10


Date: February 2018

Page 1 of 1

CONSUMERS ENERGY COMPANY

Line Description A A- BBB+ BBB

Normalized Risk Premium Analysis (Consistent Use of Historical Spread and Historical Rates)

1 Historical Spread of Gas Utility Common Stock Over Utility Bonds 3.90% 3.90% 3.90% 3.90%

2 Historical Long-Term Government Bond Return 5.02% 5.02% 5.02% 5.02%3 Corporate Spread 1.25% 1.40% 1.46% 2.08%4 Current Estimated Bond Yield (Lines 2 + 3) 6.27% 6.42% 6.48% 7.10%

5 Cost of Equity (Lines 1 + 4) 10.17% 10.32% 10.38% 11.00%

6 Average 10.47%7 Minimum 10.17%8 Maximum 11.00%

Low Interest Rate Risk Premium Analysis (Appropriate Use of Spread and Projected Long-Term Bond Rates)

9 Current Spread of Gas Utility Common Stock Over Utility Bonds 8.45% 8.45% 8.45% 8.45%

10 Projected Long-Term Government Bond Return 3.96% 3.96% 3.96% 3.96%11 Corporate Spread 1.25% 1.40% 1.46% 2.08%12 Current Estimated Bond Yield (Lines 10 + 11) 5.21% 5.36% 5.42% 6.04%

13 Cost of Equity (Lines 9 + 12) 13.66% 13.81% 13.87% 14.49%


Sources:

Line 1: Exhibit A-14 (SM-1), Schedule D-5, page 11, line 66.Line 2: Exhibit A-14 (SM-1), Schedule D-5, page 10, line 51.Line 3, 11: Exhibit A-24 (AJD-9), page 2, lines 136-139.Line 9: Exhibit A-14 (SM-1), Schedule D-5, page 11, line 67.

Line 10: Exhibit A-14 (SM-1), Schedule D-5, page 2, test year risk-free rate (Rf).

S&P Bond Rating

Corrected Risk Premium Analysis


Exhibit :AB-11


Date: February 2018

Page 1 of 1

Line Description A A- BBB+ BBB

1 Current Spread of Gas Utility Common Stock Over Utility Bonds 3.90% 3.90% 3.90% 3.90%

2 Projected Long-Term Government Bond Return 3.96% 3.96% 3.96% 3.96%3 Corporate Spread 1.25% 1.40% 1.46% 2.08%4 Current Estimated Bond Yield (Lines 2+3) 5.21% 5.36% 5.42% 6.04%

5 Cost of Equity (Lines 1+4) 9.11% 9.26% 9.32% 9.94%


Sources:

Line 1: Exhibit A-14 (SM-1), Schedule D-5, page 11, line 66.

Line 2: Exhibit A-14 (SM-1), Schedule D-5, page 2, test year risk-free rate (Rf).

Line 3: Exhibit A-24 (AJD-9), page 2, lines 136-139.

S&P Bond Rating

CONSUMERS ENERGY COMPANYRisk Premium Analysis


Exhibit :AB-12


Date: February 2018

Page 1 of 1

Avg of Last Qtrly Current Current Number Analysts' Expected Analyst30-day Dividend Annual Dividend of Analyst Average Dividend Consensus

Line Company Ticker Closing $ Payment Dividend Yield Estimates Growth Yield DCF ROE

(1) (2) (3) (4) (5) (6) (7) (8)

1 Atmos Energy Corporation ATO 83.63 0.450 1.80 2.15% 8 6.5% 2.22% 8.72%2 NiSource, Inc. NI 25.81 0.175 0.70 2.71% 10 6.4% 2.80% 9.15%3 Northwest Natural Gas Company NWN 61.42 0.470 1.88 3.06% 7 5.2% 3.14% 8.31%4 ONE Gas, Inc. OGS 70.91 0.420 1.68 2.37% 7 7.1% 2.5% 9.52%5 Southwest Gas Holdings, Inc. SWX 76.87 0.495 1.98 2.58% 7 5.8% 2.65% 8.45%6 Spire Inc. SR 70.91 0.525 2.10 2.96% 6 5.8% 3.05% 8.89%


Sources:Column 1: NASDAQ data from May 19. 2017 through June 30. 2017.Column 2: Yahoo!Finance as of June 30, 2017.

CONSUMERS ENERGY COMPANYDiscounted Cash Flow Model


Exhibit :AB-13


Date: February 2018

Page 1 of 1

Current Earnings Book Value ImpliedLine Company Ticker Beta Per Share Per Share ROE

(1) (2) (3) (4) (5)c.3/c.4

1 Atmos Energy Corporation ATO 0.70 4.50 38.50 11.69%2 NiSource NI 0.65 2.15 18.25 11.78%3 Northwest Natural Gas Company NWN 0.65 3.15 32.25 9.77%4 ONE Gas, Inc. OGS 0.70 4.00 41.45 9.65%5 Southwest Gas Holdings, Inc. SWX 0.75 4.75 57.70 8.23%6 Spire Inc. SR 0.70 4.65 48.30 9.63%


Sources:

Columns 2, 3 & 4:: Value Line Investment Survey (Gas Utilities as of June 2, 2017)

2020-2022

CONSUMERS ENERGY COMPANYComparable Earnings Analysis


Exhibit :AB-14


Date: February 2018

Page 1 of 1

Ratio Cost Weighted Cost Pretax Ratio Cost Weighted Cost Pretax

Line

1 Long-Term Debt 36.700% 4.68% 1.718% 1.72% Long Term Debt 37.48% 4.68% 1.7539% 1.75%2 Preferred Equity 0.23% 4.50% 0.010% 0.02% Preferred Equity 0.23% 4.50% 0.0104% 0.02%3 Common Equity 40.800% 9.72% 3.966% 6.49% Common Equity 40.03% 9.72% 3.8904% 6.37%4 Customer Deposits 0.150% 7.00% 0.011% 0.01% Customer Deposits 0.15% 7.00% 0.0105% 0.01%5 Other Interest Bearing Accounts 0.100% 4.00% 0.004% 0.00% Other Interest Bearing Accounts 0.10% 4.00% 0.0040% 0.00%6 Short-Term Debt 1.12% 3.53% 0.040% 0.04% Short-Term Debt 1.12% 3.53% 0.0395% 0.04%7 Deferred FIT 20.29% 0.00% 0.000% 0.00% Deferred FIT 20.29% 0.00% 0.0000% 0.00%8 Investment Tax Credit Investment Tax Credit9 Long-Term Debt 0.28% 4.68% 0.013% 0.01% Long-Term Debt 0.28% 4.68% 0.0131% 0.01%

10 Preferred Equity 0.00% 4.50% 0.000% 0.00% Preferred Equity 0.00% 4.50% 0.0000% 0.00%11 Common Equity 0.33% 9.72% 0.032% 0.05% Common Equity 0.33% 9.72% 0.0321% 0.05%12 Total Capitalization 100.00% 5.793% 8.35% Total Capitalization 100.00% 5.75395% 8.26%

13 Revenue Conversion Factor 1.6377

Rate Base ($000)

14 Consumer's Energy $5,468,043 Impact of change in Common Equity Ratio by 100 basis points -$4,758

AdjustedCapital % of % of Regulatory

13-Mos. Avg. Financial Financial CapitalFinancial Capital Jun-19 Capital Capital Structure DifferenceLong-Term Debt $6,029 47.22% 48.22% $6,157 37.48% -$128Preferred Stock $37 0.29% 0.29% $37 0.23% $0Common Equity $6,703 52.49% 51.49% $6,575 40.03% $128Total $12,769 100.00% 100.00% $12,769

Customer Deposits $25 $25 0.15%Other Interest Bearing $17 $17 0.10%Short-Term Debt $184 $184 1.12%Deferred FIT $3,333 $3,333 20.29%Investment Tax CreditLong-Term Debt $46 $46 0.28%Preferred equity $0 $0 0.00%Common Equity $54 $54 0.33%Total $16,428 $16,428 100.00%

Sources:

Rate of Return Summay

for the Test Year Ended June 30, 2019

Exhibit A-14 (AJD-1)

Schedule D-1

Proposed Capital Structure for Test Year June 30, 2019 Recommended Capital Structure for Test Year June 30, 2019

CONSUMERS ENERGY COMPANYRecommended Capital Structure

216986985.1 07411/321230

STATE OF MICHIGAN


* * * * *In the matter of the application ofCONSUMERS ENERGY COMPANYfor authority to increase its rates for thedistribution of natural gas and for other relief.

))))

Case No. U-18424

ALJ Suzanne D. Sonneborn

PROOF OF SERVICE

STATE OF MICHIGAN )) ss

COUNTY OF INGHAM )

Bryan Brandenburg, being first duly sworn, deposes and says that on February 28, 2018,

he did cause to be served the Direct Testimony and Exhibits of Jeffry Pollock and the Direct

Testimony and Exhibits of Billie S. LaConte, on behalf of the Association of Businesses

Advocating Tariff Equity, as well as this Proof of Service, in the above docket, via electronic

mail, to the persons identified on the attached service list.

____________________________________Bryan A. Brandenburg

Subscribed and sworn to before methis 28th day of February, 2018

______________________________________Jennifer M. Johnson, Notary PublicEaton County, MichiganMy Commission Expires: March 9, 2020Acting in Ingham County

216986985.1 07411/321230

SERVICE LISTMPSC Case No. U-18424

Administrative Law JudgeHon. Suzanne D. SonnebornMichigan Public Service Commission7109 W. Saginaw Hwy., 3rd FloorLansing, Michigan 48917Email: [email protected]

Counsel for MPSC StaffMeredith BeidlerAmit T. SinghMonica M. StephensLauren D. DonofrioLori Mayabb (Staff Assistant)Email: [email protected]

[email protected]@[email protected]@michigan.gov

Counsel for Retail Energy SupplyAssociation (RESA)Jennifer Utter HestonFraser Trebilcock Davis & Dunlap PCEmail: [email protected]

Counsel for Lansing Board of Water & LightRichard J. AaronKyle M. AsherJason HanselmanDykema Gossett PLLCEmail: [email protected]

[email protected]@dykema.com

Counsel for Michigan Attorney GeneralJoel B. KingCeleste M. GillJohn A. JaniszewskiEmail: [email protected]

[email protected]@[email protected]

Counsel Residential Customer GroupDon L. KeskeyBrian W. CoyerPublic Law Resource Center PLLCEmail: [email protected]

[email protected]

Consultant for Michigan AttorneyGeneralSeb CoppolaEmail: [email protected]

Counsel for Midland CogenerationVenture, LPRichard J. AaronJason T. HanselmanKyle M. AsherDykema Gossett PLLCEmail: [email protected]


216986985.1 07411/321230

Counsel for Midland CogenerationVenture, LPRichard J. AaronJason T. HanselmanKyle M. AsherDykema Gossett PLLCEmail: [email protected]


Counsel for Consumers Energy CompanyRobert W. BeachH. Richard ChambersGary A. Gensch, Jr.Kelly M. HallBret A. TotoraitisAnne M. UitvlugtTheresa A.G. StaleyEmail: [email protected]

[email protected]@cmsenergy.comkelly.hall @[email protected]@[email protected]@cmsenergy.com

Counsel for ABATEMichael J. PattwellBryan A. BrandenburgClark Hill PLCEmail: [email protected]

[email protected]

Consultants for ABATEJeffry C. PollockBillie S. LaConteKitty A. TurnerJ.Pollock, Inc.Email: [email protected]

[email protected]@jpollockinc.com

VIA ELECTRONIC CASE FILING

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