via electronic case filing
TRANSCRIPT
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
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J . P O L L O C KI N C O R P O R A T E D
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
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
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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
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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
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1. Introduction, Qualificationsand Summary
J . P O L L O C KI N C O R P O R A T E D
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
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J . P O L L O C KI N C O R P O R A T E D
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
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J . P O L L O C KI N C O R P O R A T E D
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
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J . P O L L O C KI N C O R P O R A T E D
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
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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
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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
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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%.
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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.
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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.”
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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)
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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.
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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
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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).
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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
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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)
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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.
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2. Class Cost-of-Service StudyJ . P O L L O C KI N C O R P O R A T E D
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)
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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).
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2. Class Cost-of-Service StudyJ . P O L L O C KI N C O R P O R A T E D
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
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2. Class Cost-of-Service StudyJ . P O L L O C KI N C O R P O R A T E D
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
17 Consumers’ Response to AB-CE-308.
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2. Class Cost-of-Service StudyJ . P O L L O C KI N C O R P O R A T E D
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
18 Consumers’ Response to AB-CE-247.
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2. Class Cost-of-Service StudyJ . P O L L O C KI N C O R P O R A T E D
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
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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.
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2. Class Cost-of-Service StudyJ . P O L L O C KI N C O R P O R A T E D
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.
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2. Class Cost-of-Service StudyJ . P O L L O C KI N C O R P O R A T E D
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
Q WHAT DO YOU RECOMMEND?10
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
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2. Class Cost-of-Service StudyJ . P O L L O C KI N C O R P O R A T E D
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
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2. Class Cost-of-Service StudyJ . P O L L O C KI N C O R P O R A T E D
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
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2. Class Cost-of-Service StudyJ . P O L L O C KI N C O R P O R A T E D
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
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3. Transportation Rate Design
J . P O L L O C KI N C O R P O R A T E D
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).
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3. Transportation Rate Design
J . P O L L O C KI N C O R P O R A T E D
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
Q WHAT DO YOU RECOMMEND?16
A I recommend that the proposed 4% ATL option apply to all Transportation Service17
Rate customers.18
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4. Conclusion
J . P O L L O C KI N C O R P O R A T E D
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
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Appendix A
J . P O L L O C KI N C O R P O R A T E D
APPENDIX AQualifications of Jeffry Pollock
Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.1
A Jeffry Pollock. My business mailing address is 12647 Olive Blvd., Suite 585, St.2
Louis, Missouri 63141.3
Q WHAT IS YOUR OCCUPATION AND BY WHOM ARE YOU EMPLOYED?4
A I am an energy advisor and President of J. Pollock, Incorporated.5
Q PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE.6
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
Jeffry PollockDirectPage 33
Appendix A
J . P O L L O C KI N C O R P O R A T E D
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
170401 CONSUMERS ENERGY COMPANY Association of Businesses Advocating Tariff
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
Cost-of-Service Study; Class Revenue
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
Revenue Allocation; Rate Design
8/26/2016
35
Appendix B
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
160301 METROPOLITAN EDISON COMPANY; PENNSYLVANIA
ELECTRIC COMPANY AND WEST PENN POWER
MEIUG, PICA and WPPII 2016-2537349
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
160301 METROPOLITAN EDISON COMPANY; PENNSYLVANIA
ELECTRIC COMPANY AND WEST PENN POWER
MEIUG, PICA and WPPII 2016-2537349
2016-2537352
2016-2537359
Direct PA Post-Test Year Sales Adjustment; Class
Cost-of-Service Study; Class Revenue
Allocation; Rate Design
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-
Service Study, Class Revenue
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
Revenue Allocation; Rate Design
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
Revenue Allocation; Rate Design
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-
Service Study; Class Revenue
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
130701 WESTAR ENERGY INC. and
KANSAS GAS & ELECTRIC CO.
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
Revenue Allocation; Large Commercial
and Industrial Rate Design; Storm
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
Revenue Allocation; Large Commercial
and Industrial Rate Design; Storm
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
Revenue Allocation; Large Commercial
and Industrial Rate Design; Storm
Damage Charge Rider
12/18/2014
140903 PENNSYLVANIA ELECTRIC COMPANY Penelec Industrial Customer Alliance 2014-2428743 Rebuttal PA Class Cost-of-Service Study; Class
Revenue Allocation; Large Commercial
and Industrial Rate Design; Storm
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
Revenue Allocation; Large Commercial
and Industrial Rate Design; Storm
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
Revenue Allocation, Rate Design,
Partial Services Rider; Storm Damage
Rider
11/24/2014
140902 METROPOLITAN EDISON COMPANY Med-Ed Industrial Users Group 2014-2428745 Direct PA Class Cost-of-Service Study; Class
Revenue Allocation, Rate Design,
Partial Services Rider; Storm Damage
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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-
Service Study, Class Revenue
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
130701 WESTAR ENERGY INC. and
KANSAS GAS & ELECTRIC CO.
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
130701 WESTAR ENERGY INC. and
KANSAS GAS & ELECTRIC CO.
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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-
Service Study; Class Revenue
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
120502 WESTAR ENERGY INC. and
KANSAS GAS & ELECTRIC CO.
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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-
Service Study; Class Revenue
Allocation; Rate Design
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
90402 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Traditional
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
80505 ONCOR ELECTRIC DELIVERY COMPANY &
TEXAS ENERGY FUTURE HOLDINGS LTD
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
60303 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Traditional
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
70601 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Traditional
Manufacturers Group
25060-U Direct GA Return on equity; cost of service study;
revenue allocation; ILR Rider; spinning
reserve tariff; RTP
10/24/2007
70303 ONCOR ELECTRIC DELIVERY COMPANY &
TEXAS ENERGY FUTURE HOLDINGS LTD
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
50705 SOUTHWESTERN PUBLIC SERVICE COMPANY Occidental Periman Ltd.
Occidental Power Marketing
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
50701 ENTERGY GULF STATES UTILITIES TEXAS Texas Industrial Energy Consumers 31315 Direct TX Recovery of Purchased Power Capacity
Costs
9/22/2005
50705 SOUTHWESTERN PUBLIC SERVICE COMPANY Occidental Periman Ltd.
Occidental Power Marketing
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
50705 SOUTHWESTERN PUBLIC SERVICE COMPANY Occidental Periman Ltd.
Occidental Power Marketing
EL05-19-00;
ER05-168-00
Direct FERC Fuel Cost adjustment clause (FCAC) 8/19/2005
50203 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Textile
Manufacturers Group
19142-U Direct GA Fuel Cost Recovery 4/8/2005
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
8244 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Textile
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
8022 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Textile
Manufacturers Group
17066-U Direct GA Fuel Cost Recovery 7/22/2003
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
7633 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Textile
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
7593 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Textile
Manufacturers Group
13711-U Direct GA Fuel Cost Recovery 5/11/2001
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
7423 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Textile
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
7334 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Textile
Manufacturers Group
11708-U Rebuttal GA RTP Petition 3/24/2000
7334 GEORGIA POWER COMPANY Georgia Industrial Group/Georgia Textile
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
Testimony Filed in Regulatory Proceedings
by Jeffry Pollock
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
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Appendix C
J . P O L L O C KI N C O R P O R A T E D
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
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J . P O L L O C KI N C O R P O R A T E D
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
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J . P O L L O C KI N C O R P O R A T E D
expected contribution to the Peak Day Design, which is the maximum expected1
demand on the delivery system.2
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
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
J . P O L L O C KI N C O R P O R A T E D
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
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
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J . P O L L O C KI N C O R P O R A T E D
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
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J . P O L L O C KI N C O R P O R A T E D
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
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1. Introduction, Qualificationsand Summary
J . P O L L O C KI N C O R P O R A T E D
Direct Testimony of Billie S. LaConte
1. INTRODUCTION, QUALIFICATIONS AND SUMMARY
Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.1
A Billie S. LaConte, 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 Associate Consultant at J. Pollock, Incorporated.4
Q PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE.5
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
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J . P O L L O C KI N C O R P O R A T E D
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
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J . P O L L O C KI N C O R P O R A T E D
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
Billie S. LaConteDirectPage 4
2. Fair Rate of Return
J . P O L L O C KI N C O R P O R A T E D
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).
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2. Fair Rate of Return
J . P O L L O C KI N C O R P O R A T E D
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).
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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.
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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%.
6 Direct Testimony of Srikanth Maddipati at 5.
7 The National Average compares Consumers’ recommended ROE and the National Averageauthorized ROE for 2017.
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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.
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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.
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J . P O L L O C KI N C O R P O R A T E D
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)
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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.
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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.
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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.
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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.
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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
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• 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
• Atmos Energy Corporation17
• National Fuel Gas18
• Northwest Natural Gas19
• South Jersey Industries, Incorporated20
• Southwest Gas Corporation21
• Spire, Incorporated22
• 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
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• 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
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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
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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.
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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).
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• New Jersey Resources Corporation1
• South Jersey Industries, Incorporated2
• 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
• Atmos Energy Corporation10
• NiSource, Incorporated11
• Northwest Natural Gas Company12
• ONE Gas, Incorporated13
• Southwest Gas Holdings, Incorporated14
• Spire, Incorporated15
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
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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.
28 Direct Testimony of Srikanth Maddipati at 39.
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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).
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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
33 Case No. U-18322, Notice of Proposal for Decision at 225.
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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
34 Public Utilities Reports, Inc., New Regulatory Finance, Roger Morin, PhD at 156 (Jun. 2006).
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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.
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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.
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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.
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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.
Billie S. LaConteDirectPage 30
3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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.
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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
48 Case No. U-18322, Notice of Proposal for Decision at 226.
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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
49 Direct Testimony of Srikanth Maddipati, Exhibit A-14 (SM-1) Schedule D-5 at 4.
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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.
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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
51 Direct Testimony of Srikanth Maddipati at 51.
52 Public Utilities Reports, Inc., New Regulatory Finance, Roger Morin, PhD at 298 (Jun. 2006).
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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
53 Direct Testimony of Srikanth Maddipati, Exhibit A-14 (SM-1) Schedule D-5 at 6.
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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
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3. Evaluation of Consumers’ ROE
J . P O L L O C KI N C O R P O R A T E D
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
Billie S. LaConteDirectPage 39
4. Capital Structure
J . P O L L O C KI N C O R P O R A T E D
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.
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4. Capital Structure
J . P O L L O C KI N C O R P O R A T E D
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.
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4. Capital Structure
J . P O L L O C KI N C O R P O R A T E D
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
Q WHAT DO YOU RECOMMEND?6
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
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5. Conclusion
J . P O L L O C KI N C O R P O R A T E D
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
Billie S. LaConteDirectPage 43
Appendix A
J . P O L L O C KI N C O R P O R A T E D
APPENDIX A
Qualifications of Billie S. LaConte
Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.1
A Billie S. LaConte. My business mailing address is 12647 Olive Blvd., Suite 585, St.2
Louis, Missouri 63141.3
Q WHAT IS YOUR OCCUPATION AND BY WHOM ARE YOU EMPLOYED?4
A I am an energy advisor and am currently employed by J. Pollock, Incorporated as an5
Associate Consultant.6
Q PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE.7
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
Billie S. LaConteDirectPage 44
Appendix A
J . P O L L O C KI N C O R P O R A T E D
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
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
170401 CONSUMERS ENERGY COMPANY Association of Businesses Advocating Tariff
Equity
18322 Rebuttal MI Return on Equity 9/7/2017
170401 CONSUMERS ENERGY COMPANY Association of Businesses Advocating Tariff
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
Appendix BTestimony Filed in Regulatory Proceedings
by Billie S. LaConte
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
Appendix BTestimony Filed in Regulatory Proceedings
by Billie S. LaConte
PROJECT UTILITY ON BEHALF OF DOCKET TYPE
REGULATORY
JURISDICTION SUBJECT DATE
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
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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
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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
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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
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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.
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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
Number of observations
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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
Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence
Electric utilities — summary table
Gas utilities — summary table
Number of observations
Number of observations
Number of observations
Number of observations
Number of observations
Number of observations
Number of observations
Capital structure
Capital structure
Number of observations
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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
Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence
Electric authorized ROEs: 2006 — 2017 Settled versus fully litigated cases
All cases
Average ROE (%)
Median ROE (%)
Number of observations
Average ROE (%)
Median ROE (%)
Number of observations
Average ROE (%)
Median ROE (%)
Number of observations
General rate cases versus limited issue ridersAll cases General rate cases Limited issue riders
Average ROE (%)
Median ROE (%)
Number of observations
Vertically integrated cases versus delivery only cases Vertically
Average ROE (%)
Median ROE (%)
Number of observations
Average ROE (%)
Median ROE (%)
Number of observations
Median ROE (%)
Number of observations
All cases integrated cases Delivery only cases
Average ROE (%)
Median ROE (%)
Number of observations
Average ROE (%)
Median ROE (%)
Number of observations
Average ROE (%)
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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
Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence
Gas average authorized ROEs: 2006 — 2017
Settled versus fully litigated casesAll cases
Average ROE (%)
Median ROE (%)
Number of observations
Average ROE (%)
Median ROE (%)
Number of observations
Average ROE (%)
Median ROE (%)
Number of Observations
General rate cases versus limited issue ridersAll cases Limited issue riders
Average ROE (%)
Median ROE (%)
Number of observations
Average ROE (%)
Median ROE (%)
Number of observations
Average ROE (%)
Median ROE (%)
Number of observations
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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)
2/27/17 Virginia Electric and Power Company VA 7.24 10.40 49.49 3/18 Average -2.2 (LIR,5)
2/27/17 Virginia Electric and Power Company VA 7.24 10.40 49.49 3/18 Average -8.5 (LIR,6)
2/27/17 Virginia Electric and Power Company VA 7.24 10.40 49.49 3/18 Average 0.5 (LIR,7)
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)
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Electric utility decisions
Date Company State ROR
(%) 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)
6/30/17 Virginia Electric and Power Company VA 6.74 9.40 49.49 8/18 Average 4.2 (LIR,12)
6/30/17 Virginia Electric and Power Company VA 7.24 10.40 49.49 8/18 Average -18.0 (LIR,13)
2017 2nd quarter: averages/total 7.11 9.63 48.77 597.0
Observations 9 14 9 19
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)
9/1/17 Virginia Electric and Power Company VA 6.81 9.40 50.23 8/18 Average 1.0 (LIR,15)
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
Observations 5 5 5 10
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)
[email protected];printed 2/6/2018
MPSC Case No.: U-18424Exhibit AB-6Witness: Billie S. LaConteDate: February 2018 Page 10 of 13
11 | S&P Global Market Intelligence
Regulatory Focus: Major Rate Case Decisions
Electric utility decisions
Date Company State ROR
(%) 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
Observations 19 19 19 23
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
Date Company State ROR
(%) 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
Observations 2 3 3 9
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
Observations 5 7 5 13
[email protected];printed 2/6/2018
MPSC Case No.: U-18424Exhibit AB-6Witness: Billie S. LaConteDate: February 2018 Page 11 of 13
12 | S&P Global Market Intelligence
Regulatory Focus: Major Rate Case Decisions
Gas utility decisions
Date Company State ROR
(%) 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
Observations 8 6 7 17
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
Observations 9 8 9 15
2017 Averages/total 7.26 9.72 49.88 415.6
Observations 24 24 24 54
Source: Regulatory Research Associates, an offering of S&P Global Market Intelligence
[email protected];printed 2/6/2018
MPSC Case No.: U-18424Exhibit AB-6Witness: Billie S. LaConte Date: February 2018 Page 12 of 13
13 | S&P Global Market Intelligence
Regulatory Focus: Major Rate Case Decisions
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.
[email protected];printed 2/6/2018
MPSC Case No.: U-18424Exhibit AB-6Witness: Billie S. LaConteDate: February 2018 Page 13 of 13
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
MPSC Case No.: U-18424
Exhibit :AB-8
Witness: Billie S. LaConte
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
MPSC Case No.: U-18424
Exhibit :AB-9
Witness: Billie S. LaConte
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
MPSC Case No.: U-18424
Exhibit :AB-10
Witness: Billie S. LaConte
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%
14 Average 13.96%15 Minimum 13.66%16 Maximum 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
MPSC Case No.: U-18424
Exhibit :AB-11
Witness: Billie S. LaConte
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%
6 Average 9.41%7 Minimum 9.11%8 Maximum 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
MPSC Case No.: U-18424
Exhibit :AB-12
Witness: Billie S. LaConte
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%
7 Average 8.84%8 Minimum 8.31%9 Maximum 9.52%
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
MPSC Case No.: U-18424
Exhibit :AB-13
Witness: Billie S. LaConte
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%
7 Average 10.12%8 Minimum 8.23%9 Maximum 11.78%
Sources:
Columns 2, 3 & 4:: Value Line Investment Survey (Gas Utilities as of June 2, 2017)
2020-2022
CONSUMERS ENERGY COMPANYComparable Earnings Analysis
MPSC Case No.: U-18424
Exhibit :AB-14
Witness: Billie S. LaConte
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
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
* * * * *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]
Consultant for Michigan AttorneyGeneralSeb CoppolaEmail: [email protected]
Counsel for Midland CogenerationVenture, LPRichard J. AaronJason T. HanselmanKyle M. AsherDykema Gossett PLLCEmail: [email protected]
[email protected]@dykema.com
216986985.1 07411/321230
Counsel for Midland CogenerationVenture, LPRichard J. AaronJason T. HanselmanKyle M. AsherDykema Gossett PLLCEmail: [email protected]
[email protected]@dykema.com
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]
Consultants for ABATEJeffry C. PollockBillie S. LaConteKitty A. TurnerJ.Pollock, Inc.Email: [email protected]
[email protected]@jpollockinc.com