BEFORE THE

FLORIDA PUBLIC SERVICE COMMISSION

DOCKET NO. 130040-EI

IN RE: TAMPA ELECTRIC COMPANY’S PETITION FOR AN INCREASE IN BASE RATES

AND MISCELLANEOUS SERVICE CHARGES

REBUTTAL TESTIMONY

OF JEFFREY S. CHRONISTER

TAMPA ELECTRIC COMPANY DOCKET NO. 130040-EI

FILED: 08/08/2013

TABLE OF CONTENTS 1

REBUTTAL TESTIMONY 2

OF 3

JEFFREY S. CHRONISTER 4

5

KEY CONCERNS................................................. 2 6

PROJECTED TEST YEAR.......................................... 3 7

CAPITAL STRUCTURE ADJUSTMENTS................................ 4 8

INTEREST SYNCHRONIZATION..................................... 8 9

CONSTRUCTION WORK IN PROGRESS (CWIP) IN RATE BASE............ 8 10

OTHER OPERATING REVENUES.................................... 11 11

INTANGIBLE PLANT - SOFTWARE AMORTIZATION.................... 13 12

O&M EXPENSE................................................. 20 13

BAD DEBT EXPENSE/RESERVE FOR UNCOLLECTIBLE ACCOUNTS......... 24 14

RATE CASE EXPENSE........................................... 26 15

INJURIES & DAMAGES EXPENSE.................................. 27 16

LEGAL EXPENSES.............................................. 28 17

OTHER POST-RETIREMENT EMPLOYEE BENEFITS..................... 29 18

STOCK COMPENSATION EXPENSE.................................. 31 19

PARENT ALLOCATION........................................... 31 20

SUMMARY OF REBUTTAL TESTIMONY............................... 33 21

22

23

24

25

i

TAMPA ELECTRIC COMPANY DOCKET NO. 130040-EI

FILED: 08/08/2013

BEFORE THE FLORIDA PUBLIC SERVICE COMMISSION 1

REBUTTAL TESTIMONY 2

OF 3

JEFFREY S. CHRONISTER 4

5

Q. Please state your name, business address, occupation and 6

employer. 7

8

A. My name is Jeffrey S. Chronister. My business address 9

is 702 North Franklin Street, Tampa, Florida 33602. I 10

am employed by Tampa Electric Company (“Tampa Electric” 11

or “company”) as its Controller. 12

13

Q. Are you the same Jeffrey S. Chronister who filed direct 14

testimony in this proceeding? 15

16

A. Yes, I am. 17

18

Q. What is the purpose of your rebuttal testimony? 19

20

A. The purpose of my rebuttal testimony is to address 21

errors and improper conclusions in the prepared direct 22

testimonies of Steve Chriss, testifying on behalf of the 23

Florida Retail Federation (“FRF”); Michael Gorman, 24

testifying on behalf of the Federal Executive Agencies 25

(“FEA”); Lane Kollen, testifying on behalf of the WCF 1

Hospital Utility Alliance (“HUA”); Helmuth Schultz, 2

Jacob Pous and Donna Ramas, testifying on behalf of the 3

Office of Public Counsel (“OPC”); and Jeffry Pollock, 4

testifying on behalf of the Florida Industrial Power 5

Users Group (“FIPUG”). 6

7

KEY CONCERNS 8

Q. Please summarize the key concerns and disagreements you 9

have regarding the substance of the testimonies of 10

witnesses Chriss, Gorman, Kollen, Schultz, Pous, Ramas, 11

and Pollock. 12

13

A. My key concerns and disagreements relate to the 14

following topics: 15

• Projected Test Year 16

• Capital Structure Adjustments 17

• Interest Synchronization 18

• Construction Work in Progress (“CWIP”) in Rate Base 19

• Other Operating Revenues 20

• Intangible Plant – Software Amortization 21

• O&M Expense 22

• Bad Debt Expense/Reserve for Uncollectable Accounts 23

• Rate Case Expense 24

• Injuries & Damages (“I&D”) Expense 25

2

• Legal Expenses 1

• Other Post-Retirement Employee Benefits 2

• Stock Compensation Expense 3

• Parent Allocation 4

5

PROJECTED TEST YEAR 6

Q. FRF witness Steve W. Chriss indicates concern regarding 7

the company’s use of a projected test year. Do you 8

agree with his position? 9

10

A. No. Although the use of a projected test year is not 11

required by rule or statute, the Commission has 12

extensive experience using projected test years going 13

back to the 1980’s. Most recently, the Commission 14

approved Tampa Electric’s use of a projected test year 15

in the company’s last base rate proceeding in Docket No. 16

080317-EI. 17

18

Q. Is use of a projected test year consistent with 19

decisions made by the Commission for other utilities? 20

21

A. Yes. The Commission has used projected test years for 22

Tampa Electric’s 1992 base rate proceeding, Gulf Power 23

Company’s 2011 base rate proceeding and many others. 24

The Commission authorized Florida Power & Light (“FPL”) 25

3

to implement a revenue increase based on a projected 1

test year (2013) in Order No. PSC-13-0023-S-EI, issued 2

on January 14, 2013 in Docket No. 120015-EI. 3

4

Q. Why is the use of a projected test year appropriate in 5

general and in this case? 6

7

A. Using a projected test year properly matches revenues 8

with the capital and operating costs to be incurred in 9

future periods. Basing a request on a projected test 10

year is appropriate because the test year best 11

represents operational and business conditions that will 12

be present during the time the new rates will be in 13

effect. 14

15

Q. Does the financial information for 2014 presented to the 16

Commission in the minimum filing requirements form a 17

reasonable basis for calculating the company’s 2014 18

revenue requirement and for setting customer base rates? 19

20

A. Yes. I provide a detailed explanation of the company’s 21

budget process in my direct testimony. 22

23

CAPITAL STRUCTURE ADJUSTMENTS 24

Q. FEA witness Gorman proposes on pages 17 through 20 of 25

4

his testimony a revised capital structure that allocates 1

pro forma adjustments across only investor sources of 2

capital. Do agree with this approach? 3

4

A. No. This approach is not appropriate nor is it 5

consistent with recent decisions by the Commission. 6

7

Q. Please explain. 8

9

A. In the Motion for Reconsideration from the company’s 10

last base rate proceeding, Order No. PSC-09-00571-FOF-11

EI, the Commission concluded that rate base plant 12

adjustments should be removed by a pro rata adjustment 13

over all sources of capital. 14

15

Q. What was the Commission’s treatment for non-plant 16

adjustments in the company’s 2008 base rate proceeding? 17

18

A. Non-plant items were removed through a pro rata 19

adjustment over investor sources of capital. 20

21

Q. Has the Commission ruled on non-plant adjustments more 22

recently? 23

24

A. Yes. More recently, the Commission has ruled that all 25

5

pro rata adjustments should be made over all sources of 1

capital. This approach was approved by the Commission 2

in the most recent rate proceedings for Progress Energy 3

Florida (“PEF”) and Gulf Power Company (“GPC”). The PEF 4

ruling was in Order No. PSC-10-0131-FOF-EI, issued on 5

March 5, 2010 in Docket Nos. 090079-EI, 090144-EI, and 6

090145-EI. The GPC ruling was in Order No. PSC-12-0179-7

FOF-EI, issued on April 3, 2013, Docket No. 110138-EI. 8

9

Q. What was the rationale for the Commission’s decisions to 10

make pro rata adjustments over all sources of capital? 11

12

A. The Commission’s primary rationale is to avoid a tax 13

normalization violation. The Commission decisions also 14

reflect the regulatory efficiency associated with making 15

all pro rata adjustments over all sources of capital. 16

Witness Terry Deason provides additional information and 17

historical context on this issue in his rebuttal 18

testimony on behalf of Tampa Electric Company. 19

20

Q. Do you have any other issues with witness Gorman’s 21

proposed capital structure as reflected on his exhibit 22

MPG-1? 23

24

A. Yes. Witness Gorman has inappropriately omitted the 25

6

capital structure adjustment to adjust equity for common 1

dividends payable (which is shown in Column 2 of 2

Schedule D-1a in the amount of $13.4 million). This 3

amount represents the 13-month average of the dividends 4

declared but not yet paid. Since the cash payments have 5

not yet been made, it is proper to reflect this amount 6

as equity. 7

8

Q. Does this treatment reflect prior Commission decisions? 9

10

A. Yes. The Commission has consistently supported this 11

adjustment for ratemaking purposes because it properly 12

reflects the actual equity position of the company. The 13

Commission included this adjustment in the calculations 14

supporting their Order in the company’s 2008 base rate 15

proceeding. Also, the Commission indicated the 16

following in its Order for Tampa Electric’s 1992 base 17

rate proceeding (Order No. PSC-93-0165-FOF-EI, issued 18

February 2, 1993, Docket No. 920324-EI): 19

The Commission has consistently increased equity 20

and the working capital allowance reversing the 21

average balance of common stock dividends payable. 22

TECO has filed its request consistent with this 23

method, treating common stock dividends as a 24

component of capital structure. 25

7

INTEREST SYNCHRONIZATION 1

Q. OPC witness Donna Ramas indicates on page 29 of her 2

testimony that an interest synchronization adjustment is 3

needed since OPC’s proposed amounts differ from the 4

company’s proposed amounts. Do you agree with the 5

dollar amount of her interest synchronization 6

adjustment? 7

8

A. No. However, I do agree with witness Ramas’s position 9

that after final rate base and weighted cost of debt 10

decisions are made by the Commission a new interest 11

synchronization adjustment will need to be made. It 12

appears that all parties agree on the consistent method 13

of synchronization. 14

15

CONSTRUCTION WORK IN PROGRESS (CWIP) IN RATE BASE 16

Q. Is Tampa Electric’s requested level of CWIP in the 17

amount of $174,146,000 for the 2014 projected test year 18

appropriate? 19

20

A. Yes. It is reasonable and necessary. It properly 21

reflects the budgeted amount for the 2014 test year. 22

23

Q. FRF witness Steve W. Chriss states on page 8 of his 24

testimony that the Commission should reject the 25

8

company’s request to include $174.1 million of 1

construction work in progress in rate base. Do you 2

agree with this statement? 3

4

A. No. Witness Chriss’s position is contrary to long-5

standing Commission practice and inconsistent with sound 6

regulatory policy. The long-standing practice of the 7

Commission has been to allow CWIP in rate base for the 8

short-term CWIP that is not eligible for Allowance for 9

Funds Used During Construction (“AFUDC”) under Florida 10

Administrative Code (“F.A.C.”) Rule 25-6.0141 Allowance 11

for Funds Used During Construction (New Rule 8/11/86). 12

I will refer to this type of CWIP as “CWIP Not Eligible 13

for AFUDC” hereinafter. Witness Terry Deason provides 14

additional information and historical context on this 15

issue in his rebuttal testimony on behalf of Tampa 16

Electric Company. 17

18

Q. Please provide more detail on the rule and the 19

Commission’s historical practice. 20

21

A. The rule limits AFUDC eligibility to projects that are: 22

(a) not included in rate base, (b) involve gross 23

additions to plant in excess of 0.5 percent of the sum 24

of the total balance in Account 101 – Electric Plant In 25

9

Service, and Account 106 – Completed Construction Not 1

Classified, at the time the project commences and (c) 2

are expected to be completed in excess of one year after 3

commencement of construction. The Commission practice 4

of allowing CWIP Not Eligible for AFUDC in rate base and 5

limiting AFUDC to very large projects minimizes rate 6

base in the long-term. Surveillance reporting includes 7

CWIP Not Eligible for AFUDC in rate base and excludes 8

CWIP earning AFUDC from rate base. As witness Terry 9

Deason explains further in his rebuttal testimony on 10

behalf of Tampa Electric, sound regulatory policy 11

recognizes that if CWIP Not Eligible for AFUDC is not 12

allowed in rate base, this CWIP should be provided a 13

return by making it eligible for AFUDC. However, the 14

Commission practice has been to include CWIP Not 15

Eligible for AFUDC in rate base (rather than including 16

it in AFUDC calculations) to provide the return. 17

18

Q. Has the Commission previously approved including CWIP 19

Not Eligible for AFUDC projects in rate base as proposed 20

by the company? 21

22

A. Yes. Including CWIP Not Eligible for AFUDC in rate base 23

has been the Commission’s practice for many years and 24

the Commission approved that approach in the company’s 25

10

last rate proceeding. The company’s proposed treatment 1

of CWIP Not Eligible for AFUDC in this case is 2

consistent with the Commission’s ruling in the company’s 3

last rate proceeding. 4

5

OTHER OPERATING REVENUES 6

Q. OPC witness Ramas states on page 10 of her testimony 7

that she is not recommending an adjustment for 8

Auburndale Power Partner wheeling revenue. Do you agree 9

with this position? 10

11

A. Yes. There is no change to date to the Auburndale Power 12

Partner (“APP”) commitment and there is no indication 13

from APP that this will change. At this time the 14

company does not expect any additional revenue from APP 15

and no adjustment is necessary. 16

17

Q. While discussing proposed adjustments related to the 18

change in the status of the Calpine contract, witness 19

Ramas notes on line 1 of page 9 of her testimony that 20

the reason for some revenue treatments are not clear. 21

Can you provide a clarifying explanation? 22

23

A. Yes. In Tampa Electric’s initial filing, for the year 24

2014, the company wanted to provide a more transparent 25

11

presentation of revenues from wholesale transmission 1

agreements. The final retail jurisdictional other 2

operating revenues of $42,854,000 should not include 3

(and do not include) wholesale transmission revenues. 4

In an effort to clearly delineate amounts, the company 5

included in “Per Books” (Column 1) of Schedule C-5 the 6

wholesale transmission revenues. The company then 7

removed from lines 26 and 29 the Calpine and Auburndale 8

revenues (Columns 10 and 11) as Jurisdictional 9

Adjustments. On Schedule C-2 page 3 of 7 (Columns 2 and 10

3), these jurisdictional adjustments are reflected as 11

“Company Adjustments” – due to the company’s decision to 12

have a more transparent presentation. 13

14

Q. Are there references in witness Ramas’ testimony to your 15

MFR treatments that need to be corrected? 16

17

A. Yes. At the top of page 9 of witness Ramas’ testimony 18

she indicates that Calpine revenues were reflected as 19

jurisdictional revenues in Tampa Electric’s filing. As 20

stated above, the wholesale transmission revenues are 21

not part of jurisdictional other operating revenues. I 22

recognize that the company’s MFR presentation described 23

above left room for confusion. However, I think that 24

the statements made in witness Ramas’ testimony reflect 25

12

her position that normal treatment for wholesale 1

transmission revenue is exclusion from jurisdictional 2

amounts. Tampa Electric agrees with that position. 3

4

Q. Are any other clarifications needed? 5

6

A. Yes. The company proposed (and continues to propose) to 7

adjust separation factors to properly reflect the costs 8

which should be associated with Tampa Electric’s 9

wholesale transmission agreements – and their most 10

recently confirmed volumes. Wholesale transmission 11

revenues should be excluded from retail revenue 12

requirement calculations. But retail revenue 13

requirement calculations should be adjusted by the most 14

recently known information about volumes that impact 15

cost separation. It appears that all parties agree on 16

these concepts. 17

18

INTANGIBLE PLANT - SOFTWARE AMORTIZATION 19

Q. OPC witness Pous on page 3 lines 4 through 19 of his 20

testimony under “what is the purpose of your testimony?” 21

proposes (1) a 15-year amortization period for all 22

software and (2) an increase from $3.327 million to 23

$5.271 million for the amortization reserve for the 24

Enterprise Resource Planning (“ERP”) software system. 25

13

Do you agree with these proposals? 1

2

A. No. In describing the purpose of his testimony, witness 3

Pous addresses two issues. The first issue witness Pous 4

addresses is the company’s proposal for continuation of 5

a five-year amortization period for the vast majority of 6

the investments in its software systems and a request 7

for a 10-year amortization for its newly installed ERP 8

software system. Witness Pous recommends adjusting 9

these amortization periods to 15 years. Witness Pous 10

provides no study or support for his recommendation. 11

The second issue witness Pous addresses relates to the 12

level of amortization reserve associated with the 13

company’s newly installed ERP software system. He 14

states that the company has booked amortization expense 15

into the accumulated provision for amortization through 16

the end of 2014 based on a 10-year amortization period. 17

He asserts that the Commission has only approved a five-18

year amortization period for software in prior 19

proceedings. 20

21

Q. Do you agree with these positions? 22

23

A. No. The five-year amortization period was not at issue 24

in the company’s last rate proceeding. The Commission 25

14

has not addressed amortization of software in the 1

company’s depreciation orders or studies. The 2

amortization periods proposed by the company in this 3

case were filed with the Federal Energy Regulatory 4

Commission (“FERC”) and were accepted in two wholesale 5

settlement agreements. The company’s proposed 6

amortization over 10 years is reasonable and 7

appropriate. 8

9

Q. Why did the company not seek approval of a 10-year 10

amortization period for the new ERP system when it filed 11

its depreciation study with the Commission in April 12

2011? 13

14

A. The company follows the long-standing practice of the 15

Commission that the Depreciation Rule 25-6.0436, F.A.C. 16

applies to depreciable tangible property and not to 17

intangible property like rights, consents and software. 18

The company has never requested an amortization period 19

for software in its petitions to change depreciation 20

rates and the Commission and staff have never requested 21

such proposals. To its knowledge, the company has not 22

seen any other Florida electric investor-owned utility 23

file proposals for software amortization in their 24

depreciation studies. 25

15

The company believes that the Commission’s exclusion of 1

software amortization periods from depreciation study 2

requirements is appropriately based on the fundamental 3

differences between tangible and intangible assets. 4

Tangible assets require physical removal and disposal. 5

Depreciation studies can use that activity to analyze 6

service lives and net salvage factors. Software is a 7

set of computer codes that does not require physical 8

removal when taken out of service. To more efficiently 9

account for software additions and retirements, the 10

company adds new software systems or upgrades to Account 11

303 (Intangible Property) and amortizes the cost over 12

the amortization period. The cost is retired when the 13

intangible asset is fully amortized. 14

15

Q. What period has the company historically used for 16

amortizing software? 17

18

A. The company has historically used a five-year 19

amortization period and this period is still appropriate 20

for most software systems. Software upgrades occur 21

about every five years and often replace initial 22

configuration and add new functionality. Support of the 23

system by vendors is dependent on implementing new 24

versions of the software. 25

16

Q. Then why has the company proposed using a 10-year period 1

for amortizing the cost of its new ERP system? 2

3

A. The new ERP system is significantly different from 4

previous software systems in the magnitude and breadth 5

of its functional scope. The company - through industry 6

surveys - has seen that many investor-owned utilities 7

(“IOU”) use between 10 to 12 year amortization periods 8

for major ERP Systems and five years for smaller 9

software systems. Witness Pous recognizes the 10 to 12-10

year amortization periods used by other companies on 11

page 20 lines 13 and 14, referring to them as: “…the 12

realistic lower-end level 10- to 12-year life proposed 13

by some other utilities for major software systems.” 14

15

Q. What has the Commission accepted in other cases for 16

software amortization lives? 17

18

A. In PEF’s Docket No. 090079-EI, the company proposed the 19

following rates/lives for software systems: Corporate – 20

Misc. Intangible 303 - 20 percent (5 years), CSS 21

Intangible 303 – 10 percent (10 years) and Transmission 22

Intangible 303 – 14.29 percent (7 years) (MFR Schedule 23

B-7 Plant Balances by Account and Sub-Account, page 10 24

of 28, rows 5 through 8, column B). In Order No. PSC-25

17

10-0398-S-EI, issued on June 18, 2010 [Order Approving 1

Stipulation and Settlement] the proposed amortization 2

lives were not changed. 3

4

On page 20 lines 5 through 8, witness Pous states that 5

FPL, in its recent rate proceedings, proposed changing 6

the amortization lives from 5 years to 20 years for its 7

new general ledger accounting software system; however, 8

he fails to mention that FPL continues to use five years 9

for all other software systems. 10

11

GPC has consistently used seven years for their software 12

amortization period. 13

14

The Commission has recognized the impact on 15

technological tangible assets of technological 16

obsolescence in its approval of lives between three to 17

seven years for personal computer workstations, servers, 18

telecommunication equipment and even tools, furniture 19

and fixtures. Witness Pous’s proposed 15-year 20

amortization period for all software projects is 21

inconsistent with the amortization periods approved in 22

other Orders. 23

24

Q. On pages 9 through 11, witness Pous opines, “the 25

18

company’s admission that it has not performed any such 1

studies demonstrates not only the lack of support for 2

the company’s proposal, but also a violation of FERC’s 3

current requirement guidelines.” Do you agree with this 4

position? 5

6

A. Absolutely not. Throughout his testimony, witness Pous 7

quotes requirements for depreciation and substitutes the 8

word software as if they are synonymous. As mentioned 9

previously, the F.A.C. Rule 25-6.0436 [Depreciation] 10

does not mention “amortization”. F.A.C. Rule 25-6.04361 11

[Subcategorization of Electric Plant for Depreciation 12

Studies and Rate Design] does not list Account 303 – 13

Miscellaneous Intangible Plant as a required category 14

for depreciation studies. The company has filed 15

depreciation studies since the late eighties and has 16

never filed an engineering study for software assets. 17

No Florida IOU has filed an engineering study for 18

software assets. The Commission has accepted all of 19

Tampa Electric’s depreciation studies as being in 20

compliance with the depreciation rules. The company 21

filed Section 205 filings to get FERC approval for the 22

Commission Order on change in depreciation rates as well 23

as the 5- and 10-year software amortization periods for 24

two wholesale rate cases. Neither FERC nor the 25

19

interveners objected to the company’s amortization 1

periods for software. That is strong proof that the 2

company did not violate any FERC or Florida rules 3

associated with this issue. 4

5

O&M EXPENSE 6

Q. Several intervener witnesses have suggested that the 7

operations and maintenance (“O&M”) requested in this 8

proceeding should be reduced because it is higher than 9

historical amounts from the last three years. Is this 10

approach reasonable? 11

12

A. No. Witness Kollen proposes to adjust generation O&M 13

based on a 3-year historical average level of expenses. 14

Witness Kollen also proposes to adjust transmission and 15

distribution (“T&D”) expenses based on the 2012 16

historical level of expenses. This backward-looking 17

approach results in a negative outcome for positive 18

business practices. 19

20

Q. Please explain. 21

22

A. The company has worked hard to control costs. If 23

historical costs are used to set future rates, then the 24

company is negatively impacted by its own efforts to 25

20

take steps to benefit the customer. More importantly, 1

making a backwards looking adjustment based on 2

historical averages using years of abnormally low 3

spending effectively locks in spending levels that are 4

not sustainable. 5

6

Q. How do company cost control efforts benefit customers? 7

8

A. In two ways: (1) In periods of low revenue, cost 9

control efforts allow the company to maintain financial 10

health; thus, the company can go longer without asking 11

the Commission to increase rates. (2) Many cost 12

control efforts eliminate or temper future cost 13

increases. Cost control efforts that lower future costs 14

in turn lower future revenue requirements. 15

16

Q. Can you give an example of this? 17

18

A. Yes. The company implemented several process and system 19

improvements that significantly lowered bad debt 20

expense. The Commission approved $8 million for this 21

expense in the company’s base rate proceeding five years 22

ago. In that year, the company incurred over $7.5 23

million of expense. In this proceeding the company is 24

asking to recover 2014 expense of $3.6 million. Tampa 25

21

Electric’s efforts to reduce bad debt expense are 1

detailed in rebuttal testimony Tampa Electric witness 2

Karen J. Lewis. She also explains why the Commission 3

should not make an adjustment to lower bad debt expense 4

in the 2014 projected test year. 5

6

Q. Various intervener witnesses have criticized the total 7

level of the company’s 2014 O&M expenses as well as 8

specific components of 2014 O&M expenses. Do you agree 9

with their observations and criticisms? 10

11

A. No. I believe the intervener witnesses have improperly 12

evaluated the company’s proposed O&M expense levels for 13

2014. 14

15

Q. Please explain. 16

17

A. First, I think it would be helpful to put the company’s 18

proposed level of O&M spending in the proper 19

perspective. In the company’s last base rate 20

proceeding, the Commission approved a total 21

jurisdictional amount of O&M expense of approximately 22

$355 million for the 2009 test year. The company’s 23

proposed total jurisdictional O&M expenses for the 2014 24

test year in this proceeding is $364 million, only $9 25

22

million more than the level approved for 2009. I hope 1

the Commission will consider this overall level of 2

spending for 2014 to be reasonable and to keep this 3

overall spending level in mind as it evaluates the 4

specific O&M adjustments proposed by the interveners. 5

6

Second, as I mentioned above, I believe that the 7

interveners have inappropriately relied on historical 8

averages when calculating the dollar amounts of certain 9

adjustments. The Commission should reject this approach 10

to evaluating and adjusting proposed O&M expense levels 11

because the historical averages used by the interveners 12

include two atypical years – 2011 and 2012 – when the 13

company dramatically cut spending to unsustainably low 14

levels in light of unforeseen and unprecedented revenue 15

shortfalls. Including these unusually low spending 16

years in the average and computing an adjustment based 17

on the average yields a result that “locks in” 18

unsustainably low spending levels and will impair the 19

company’s ability to provide safe and reliable service 20

to its customers. 21

22

Third, as explained by rebuttal witness Terry Deason on 23

behalf of Tampa Electric, the “looking backwards” 24

approach to evaluating O&M expense spending levels is 25

23

inconsistent with the idea of a projected test year. 1

2

Finally, I am concerned about the high level approach to 3

adjusting O&M expense levels advocated by the 4

interveners. Although averages and benchmarks can be 5

useful tools for organizations to use in high-level 6

analysis of spending, the intervener witnesses have not 7

identified any particular operational activity that the 8

company should forego. For example, while witness 9

Schultz is proposing that the company’s headcount be 10

reduced by 114 people, he has not identified a single 11

position that the company should not add. Likewise, in 12

the operations areas, the intervener witnesses have not 13

identified any particular aspect of generation 14

maintenance, call center operation or any other 15

particular business activity that the company should not 16

pursue. I would suggest that the company’s operational 17

witnesses are in the best position to assess and explain 18

the level of spending the company needs to provide safe 19

and reliable service to our customers. 20

21

BAD DEBT EXPENSE/RESERVE FOR UNCOLLECTIBLE ACCOUNTS 22

Q. HUA witness Kollen states on pages 28 and 29 of his 23

testimony that the increase in uncollectable accounts 24

expense is excessive and should not be recovered. Do 25

24

you agree with this position? 1

2

A. No. First, the budget for bad debt expense increases 3

less than $600,000 from 2013 to 2014. More importantly, 4

the 2014 projected amount is well below actual annual 5

expense incurred from 2007 to 2011. It is true that the 6

2012 expense was low as the company implemented new 7

processes and technology to capture substantial 8

uncollected dollars. However, focusing on the unique 9

low expense in one year does not make sense. Instead, 10

the 2014 budget of $3.6 million can be put into context 11

by examining the following actual amounts: 12

2007 - $5.5 million 13

2008 - $6.8 million 14

2009 - $7.5 million 15

2010 - $7.8 million 16

2011 - $4.1 million 17

18

Finally, the bad debt expense proposed by Tampa Electric 19

is actually $4.3 million lower than the amount used by 20

the Commission to set rates five years ago. Tampa 21

Electric’s projected expense is reasonable and 22

appropriate. 23

24

Witness Lewis explains the activities undertaken by the 25

25

company in the last several years to manage bad debt 1

expense. 2

3

RATE CASE EXPENSE 4

Q. OPC witness Schultz asserts that the company’s rate case 5

expense request is excessive. He argues that since the 6

company is not small it should be able to assemble a 7

rate filing without significant assistance. Do you 8

agree with this statement? 9

10

A. No. Much like the interveners, who have retained 11

outside resources to assist in preparing their case, 12

Tampa Electric has retained consultants to serve as 13

expert witnesses and assist in case preparation. With 14

the significant discovery submitted by interveners in 15

this particular proceeding, the need for outside help 16

has been even greater. The company is staffed to handle 17

on-going, day-to-day responsibilities, so the additional 18

workload of the rate filings requires supplementing the 19

existing team. To do otherwise would be costly to 20

customers. 21

22

Q. Witness Schultz recommends that rate case expense should 23

be amortized over five years rather than three. Do you 24

agree? 25

26

A. No. Based on the Need Determination approved by the 1

Commission in Docket No. 120234-EI in Order No.PSC-13-2

0014-FOF-EI, issued on January 8, 2013, Tampa Electric 3

will be investing in base load generation at the Polk 4

Power Station. This will likely require the company to 5

seek rate relief within three years to recover prudent 6

costs associated with this significant project. Given 7

the timing of the company’s next base rate proceeding 8

filing, three years is an appropriate amortization 9

period for rate case expense and no adjustment should be 10

made. 11

12

INJURIES & DAMAGES EXPENSE 13

Q. HUA witness Kollen states on page 25 of his testimony 14

that injuries and damages expense should be reduced by 15

$1.728 million to reflect historical experience. Do you 16

agree with this position? 17

18

A. No. First, injuries and damages (“I&D”) expense – both 19

actual and budgeted – is the result of recommendations 20

from outside actuaries. The actuaries use historical 21

loss experience but also consider many current and 22

future factors that would properly go into an analysis 23

of this type of liability. In addition, the I&D expense 24

proposed is only about $250,000 higher than the 2012 25

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actual amount – and about $400,000 lower than the amount 1

used by the Commission to set rates five years ago. 2

Tampa Electric’s projected expense is reasonable and 3

appropriate. 4

5

LEGAL EXPENSES 6

Q. HUA witness Kollen states on pages 29 and 30 of his 7

testimony that the increase in legal expense is 8

excessive and proposed recovery should be reduced by 9

$1.521 million. Do you agree with this position? 10

11

A. No. First, the budget for legal expense increases less 12

than $200,000 from 2013 to 2014. The 2014 projected 13

amount is reflective of circumstances that will be 14

present during the time that future rates will be in 15

effect. They also involve on-going efforts to reduce 16

costs to be borne by customers – as well as protect 17

revenues that lower revenue requirements for customers. 18

Legal expense projected for 2014 is reasonable 19

considering actual expense over the last five years. 20

Finally, the legal expense proposed by the company is 21

less than $900,000 greater than the amount used by the 22

Commission to set rates five years ago. Tampa 23

Electric’s projected expense is reasonable and 24

appropriate. 25

28

Q. HUA witness Kollen and OPC witness Ramas suggest that 1

$520,000 included in projected test year expenses for 2

the pending litigation with Verizon regarding pole 3

attachment charges be removed. Do you agree with this 4

position? 5

6

A. No. The company expects to continue incurring legal 7

expenses associated with efforts to collect Verizon pole 8

attachment revenue. It is very important to note that 9

the 2014 test year contains approximately $3.8 million 10

of pole attachment revenues from Verizon that are 11

currently being disputed. The requested revenue 12

requirement is $3.8 million lower as a result. 13

Customers are benefitting by the inclusion of this 14

disputed revenue amount in the company’s filing. It is 15

only reasonable that the litigation costs to capture 16

these revenues be recovered through proposed operating 17

expense. Including the requested Verizon legal fees is 18

both balanced and appropriate. 19

20

Tampa Electric witness S. Beth Young discusses this 21

issue further in her rebuttal testimony. 22

23

OTHER POST-RETIREMENT EMPLOYEE BENEFITS 24

Q. Should an adjustment be made to rate base for unfunded 25

29

Other Post-Retirement Employee Benefits (“OPEB”) 1

liability and any associated expense? 2

3

A. No. The company has consistently recorded OPEB 4

liability and expense over time. OPEB includes certain 5

post-retirement health care and life insurance benefits. 6

The accounting for OPEB incorporates the future defined 7

benefit for both active employees as well as those 8

already retired. The present value of future benefits 9

are calculated and provided by Tampa Electric’s 10

actuaries. The company records expense while 11

recognizing the recommended liability as a reserve. The 12

company pays retiree medical claims as incurred and 13

charges the reserve. The reserve amount serves to 14

reduce working capital and therefore rate base in the 15

company’s proposed revenue requirement as filed. 16

17

Q. Would an adjustment be consistent with the Commission’s 18

previous decisions for Tampa Electric? 19

20

A. No. In Tampa Electric’s last base rate proceeding 21

(Order No. PSC-09-0283-FOF-EI, issued April 30, 2009, in 22

Docket No. 080317-EI), the Commission found that the 23

company’s OPEB balances and expenses were reasonable: 24

We find that there is sufficient record evidence to 25

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demonstrate that Tampa Electric’s unfunded OPEB 1

liability is reasonable and has been included in 2

rate base. Thus, no adjustment to the company’s 3

rate base concerning unfunded OPEB liability is 4

warranted. (Page 22) We find that TECO has 5

presented sufficient information to demonstrate 6

that its Other Post Employment Benefits Expense is 7

reasonable. (Page 54) 8

9

STOCK COMPENSATION EXPENSE 10

Q. OPC’s witness Schultz, III states on page 24 lines 13-17 11

that “I would then recommend that the $5,084,200 of 12

expense for the Tampa Electric stock compensation be 13

reduced by $1,881,154 so that only 63 percent is 14

expensed. This would be consistent with the company’s 15

expense factor for pensions and other employee 16

benefits.” Do you agree with this treatment? 17

18

A. No. The company does not capitalize stock compensation 19

expense. To use 63 percent would ignore the actual 20

manner in which this expense is reflected in the cost 21

profile of the company. 22

23

PARENT ALLOCATION 24

Q. HUA witness Kollen and OPC witness Ramas suggest the 25

31

test year expenses be reduced by $2.9 million to reflect 1

the projected annual impact of the proposed TECO Energy 2

acquisition of New Mexico Gas Company ("NMGC") that was 3

provided by the company. Do you agree with this 4

suggestion? 5

6

A. No. The acquisition of NMGC is still pending and 7

uncertain. Therefore, it would not be appropriate for 8

the company to make any adjustment to parent allocation 9

due to the timing and uncertainty of this acquisition. 10

The company’s uncertainty of completing the NMGC 11

acquisition is driven by the company’s inability to 12

guarantee the final outcome. 13

14

Q. OPC witness Ramas states on page 24, line 17, an 15

additional $378,082 of allocated cost be removed to 16

account for shifting of costs from other current 17

subsidiaries of TECO Energy to Tampa Electric in the 18

test year. Do you agree with this statement? 19

20

A. No. The parent company has consistently applied the 21

current Modified Massachusetts Method to calculate the 22

allocation of parent cost to its subsidiaries since 23

2002. TECO Energy is a publicly traded company that is 24

subject to certain compliance costs. Many of these 25

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costs are not dependent on the financial profiles or 1

number of affiliates that are supported by these 2

corporate level services. Therefore, future changes in 3

the subsidiary earnings or asset profiles will not 4

change the total allocable expenses projected at the 5

parent company and thus should not result in any 6

adjustment to Tampa Electric’s portion of parent 7

allocations. 8

9

SUMMARY OF REBUTTAL TESTIMONY 10

Q. Please summarize your rebuttal testimony. 11

12

A. I have delineated the concerns and disagreements I have 13

regarding the substance of the testimonies of witnesses 14

Chriss, Gorman, Kollen, Schultz, Pous, Ramas, and 15

Pollock. Their assertions contain a variety of points 16

that are not accurate, not logical, not appropriate 17

and/or not in agreement with the Commission’s regulatory 18

policies in a number of areas. I have presented facts 19

and information that support the company’s petition, the 20

reasonableness and prudence of amounts and positions 21

presented by Tampa Electric, and the appropriateness of 22

the revenue requirement contained in the company’s 23

filing. 24

25

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Q. Does this conclude your rebuttal testimony? 1

2

A. Yes, it does. 3

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