tampa electric website · docket no. er10-2061-000 exhibit no. tec-100 filed: 07/30/2010 amended:...

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

DOCKET NO. ER10-2061-000

DIRECT TESTIMONY AND EXHIBIT

OF

ALAN C. HEINTZ

ON BEHALF OF TAMPA ELECTRIC COMPANY

AMENDED: AUGUST 12, 2010

DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010

AMENDED: 08/12/2010

ALAN C. HEINTZ 1

DIRECT TESTIMONY AND EXHIBIT INDEX 2

3

Introduction and Qualifications ..............................1 4

Purpose of Testimony and Background...........................4 5

Formula Rate in Detail.......................................12 6

Exhibit No. TEC-101 ............................................... 30 7

Summary of Testimony Experience 8

Exhibit No. TEC-102 ............................................... 40 9

Completed Formula – Initial Period Revenue Requirement 10

11

12

13

14

15

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17

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AMENDED: 08/12/2010

BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION 1

PREPARED DIRECT TESTIMONY 2

OF 3

ALAN C. HEINTZ 4

ON BEHALF OF TAMPA ELECTRIC COMPANY 5

6

Introduction and Qualifications 7

Q. Please state your name, title and your business address. 8

9

A. My name is Alan C. Heintz. I am a vice president of 10

Brown, Williams, Moorhead & Quinn, Inc. (“BWMQ”). My 11

business address is 1155 15th Street, NW, Suite 400, 12

Washington, DC 20005. 13

14

Q. What are your duties in your current position? 15

16

A. I provide consulting services on matters relating to 17

transmission, power sales, ancillary services and 18

reliability must-run units. I have been actively involved 19

as a consultant to numerous Independent System Operators 20

(“ISO”) and Regional Transmission Organizations (“RTO”), 21

as consultant to certain participants of the Midwest ISO, 22

and to such entities as American Transmission Company, 23

LLC and Trans-Elect. I have advised these clients on 24

transmission and congestion pricing, treatment of pre-25


AMENDED: 08/12/2010

2

existing arrangements, losses, and ancillary services, as 1

well as non-rate terms and conditions of their tariffs. I 2

provide advice on transmission pricing matters to several 3

transmission-owning members of the PJM Interconnection, 4

LLC and the Southwest Power Pool, Inc. 5

6

Q. Please describe your professional experience. 7

8

A. I was employed by the FERC from November 1985 to February 9

1995. I served as a Public Utilities Specialist in the 10

[Electric] Rate Filings Branch from November 1985 to 11

October 1989. In November 1989, I was promoted to Section 12

Chief in the Division of [Electric] Applications, and was 13

responsible for supervising the review of the terms, 14

conditions, and rates of electric rate applications for 15

such services as interchange power, requirements power, 16

and transmission. During my tenure with the FERC, I 17

prepared or supervised the preparation of memoranda 18

recommending acceptance, rejection, deficiency, or 19

investigation. Several of these cases set important 20

precedents on electric transmission pricing, such as the 21

merger compliance transmission tariffs for Northeast 22

Utilities, the first generation of open access 23

transmission tariffs (“OATT”) filed by utilities such as 24

Entergy Services, Louisville Gas & Electric Co., Florida 25


AMENDED: 08/12/2010

3

Power & Light Co., Kansas City Power & Light Co., 1

American Electric Power Co., and the Pennsylvania 2

Electric Company case involving Penntech Papers, Inc. 3

4

I also taught a one-year course to FERC staff and gave 5

several presentations to the Edison Electric Institute 6

Interconnection and Interchange Arrangements Committee on 7

the pricing of power and transmission services. From 8

February 1995 through October 2000, I was a Vice 9

President of Stone & Webster Management Consultants, Inc. 10

In this position, I provided consulting services to 11

numerous electric utilities on matters involving rate and 12

implementation strategies for developing OATT filings, 13

and organizing independent system operators and regional 14

transmission organizations. I joined R. J. Rudden 15

Associates, Inc. in November 2000 as a Vice President, 16

where I continued providing consulting services to the 17

electric industry. I joined BWMQ in February 2004. 18

19

Q. Please summarize your other experience testifying before 20

regulatory bodies and courts on utility-related matters. 21

22

A. During my tenure at the FERC, I was assigned to the 23

Commission’s advisory staff and, therefore, was precluded 24

from testifying before the FERC. However, while at the 25


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4

FERC, I presented cases publicly to the FERC 1

Commissioners at their bi-weekly public meetings and was 2

the technical contact to the Commissioners in numerous 3

cases. Since leaving the employ of FERC, I have filed 4

testimony before the FERC in numerous proceedings. I have 5

also testified before the British Columbia Utilities 6

Commission in Canada, the Illinois Commerce Commission, 7

the Maine Public Utilities Commission, the United States 8

Court of Federal Claims, and the United States District 9

Court for the District of Florida. A summary of the 10

testimony I have filed in various proceedings is shown in 11

Exhibit No. TEC-101. 12

13

Q. Please describe your educational background. 14

15

A. I received the degree of Bachelor of Science in Business 16

and the degree of Bachelor of Arts in Economics from the 17

University of Colorado, Boulder, Colorado, in May 1982. I 18

also received the degree of Master of Business 19

Administration in Finance from the George Washington 20

University in Washington, DC, in December 1988. 21

22

Purpose of Testimony and Background 23

Q. What is the purpose of your testimony? 24

25


AMENDED: 08/12/2010

5

A. The purpose of my testimony is to present Tampa Electric 1

Company’s (“Tampa Electric” or “Company”) electric power 2

formula rate applicable to its AR-1 Tariff (to be renamed 3

Wholesale Requirements Tariff (“Tariff”)). 4

5

The formula rate has two components that will be 6

incorporated into Tampa Electric’s Tariff. The first is 7

Appendix A, consisting of 22 schedules, which contains 8

the formula to be used to determine the demand and energy 9

related costs and associated charges (the “Formula”). The 10

second component consists of the implementation protocols 11

that describe how Tampa Electric will update the Formula 12

in future years, the review procedures to be followed, 13

how customer challenges will be resolved, and how changes 14

to the annual rate will be implemented. These protocols 15

will be included in the Tariff as Appendix B. Appendix A 16

and B are collectively the “Formula Rate”. 17

18

Q. Please describe the exhibits you are sponsoring in 19

addition to this direct testimony. 20

21

A. I am sponsoring the following exhibits: 22

Exhibit No. TEC–101 Summary of Testimony Experience 23

Exhibit No. TEC–102 Completed Formula – Initial 24

Period Revenue Requirement 25


AMENDED: 08/12/2010

6

Q. Please describe the filing and the rates proposed in the 1

filing. 2

3

A. Tampa Electric proposes a cost-based power supply Formula 4

and a stated customer charge, to be effective October 1, 5

2010. The current charges assessed customers for capacity 6

and energy delivered under the current rates are stated 7

rates which have not been modified since 1993. Since the 8

current rates were made effective, the Company has added 9

significantly to its power production facilities, the 10

costs of which must be recovered in its rates. The 11

proposed Formula will not only reflect Tampa Electric’s 12

current costs, it will also relieve Tampa Electric and 13

the customers of the necessity of future filings of 14

stated rates, which will likely be necessary in the 15

absence of the proposed formula rate mechanism. 16

17

Q. Please describe how the rates will be implemented. 18

19

A. The “Rate Year” will run from August 1st through July 31st, 20

except for the initial, proposed partial Rate Year 21

(October 1, 2010 through July 31, 2011). The Formula will 22

produce three specific rates. Two of those rates will 23

remain constant during the Rate Year: (1) the Generation 24

Capacity Charge (“GCC”) (per kW/month), shown on Schedule 25


AMENDED: 08/12/2010

7

A-1, and 2) the Non-Fuel Variable Cost Energy Charge 1

(“NFVC”) (per kWh), shown on Schedule A-2. The Fuel and 2

Purchased Power Charge (“FPPC”), also shown on Schedule 3

A-2, will be billed monthly at the actual cost rate (per 4

kWh), during the month following the month that the costs 5

were incurred. 6

7

Transmission loss costs are recovered by applying the 8

Transmission Loss Factor (“TLF”) to billing determinants 9

or charges. The TLF is applied in the calculation of the 10

GCC, NFVC and FPPC that will be billed to customers, as 11

shown on Formula Schedules A-1 and A-2. While the TLF is 12

updated every April, the most current TLF will be used 13

throughout the Rate Year. 14

15

The GCC and NFVC rates will be derived from their 16

underlying annual fixed or variable revenue requirements 17

as calculated by the Formula. A true-up component 18

(including interest) will reconcile the preliminary rate 19

year revenue requirement with the final, actual rate year 20

revenue requirement for each rate component. The 21

preliminary rate year revenue requirement is the result 22

of populating the Formula with Tampa Electric’s prior-23

year actual costs, the majority of which (for the GCC and 24

NFVC rates) are taken directly from the Company’s FERC 25


AMENDED: 08/12/2010

8

Form No. 1, and projected capital additions. 1

2

For example, the rates proposed to be in effect for the 3

(partial) 2010 Rate Year (ending July 31, 2011) have been 4

calculated by populating the Formula with Tampa 5

Electric’s 2009 costs, billing determinants (loads and 6

energy sales) and projected 2010 capital additions. In 7

2011 (after publication of Tampa Electric’s 2010 FERC 8

Form No. 1), the Formula will be populated with the 9

Company’s 2010 actual data. The differences in revenue 10

requirements (fixed and energy-related) due to the 11

differences between 2009 and 2010 actual inputs to the 12

Formula will be used to calculate true-up amounts with 13

interest that will be converted to monthly charges and 14

collected from or refunded to customers over the twelve-15

month period of the 2011 Rate Year (beginning August 1, 16

2011). The demand and energy charges for the 2011 Rate 17

Year will be based on 2010 actual costs, adjusted for 18

2011 projected capital additions. This process will 19

continue each year. 20

21

Currently, requirements customers are billed actual fuel 22

and purchased power costs, as allowed by the FERC 23

regulations, through the Company’s existing wholesale 24

fuel adjustment clause. Now, as part of the Formula Rate, 25


AMENDED: 08/12/2010

9

Tampa Electric proposes to bill the requirements 1

customers for the actual costs of fuel and purchased 2

power on a monthly basis. The FPPC billing may also 3

reflect any prior period adjustments or corrections. 4

Schedule A-2.1 shows the Formula template for the 5

calculation of the monthly FPPC. Tampa Electric will also 6

continue to bill any over/(under) recovery associated 7

with the current wholesale fuel adjustment clause during 8

the initial partial Rate Year, until those dollars are 9

dispensed or recovered. The Formula model combines the 10

NFVC and FPPC to derive the Energy Charge (“EC”) (per 11

kWh). The EC adjusted for transmission losses is 12

calculated on Schedule A-2, line 21, to provide a sample 13

calculation based on 2009 historical costs. As previously 14

stated, the NFVC portion of the EC will remain constant 15

over the Rate Year. However, because Tampa Electric will 16

be calculating the FPPC on a monthly basis, Tampa 17

Electric will prepare Schedule A-2.1 monthly to generate 18

the FPPC that will be charged to the customers. 19

20

The proposed stated customer charge is based upon actual 21

costs for requirements customer billing and reporting 22

activities, and the customer charge will remain fixed 23

absent a Federal Power Act (“FPA”) Section 205 or 206 24

filing to adjust its level in the future. 25


AMENDED: 08/12/2010

10

Q. Does the proposed Formula employ any estimated or 1

forecasted costs to derive the demand and energy rates? 2

3

A. Yes. Tampa Electric has adjusted plant in service to 4

include projected capital additions for the current year, 5

to reduce the magnitude of the true ups. As indicated 6

above, the amounts will be trued up, with interest during 7

the next rate period. The true-up process reconciles 8

formulaic results to Tampa Electric’s actual costs 9

consistent with Baltimore Gas and Electric Co., Pepco 10

Holding Inc.’s transmission-owning affiliates (Atlantic 11

City Electric Company, Delmarva Power & Light Company and 12

Potomac Electric Power Company), Commonwealth Edison Co., 13

UGI Utilities, Inc., Trans-Allegheny Interstate Line 14

Company, PPL Electric Utilities Corporation (“PPL”), 15

Minnesota Power Company and other similar formulas that 16

have been previously approved by the Commission. 17

18

Q. Please provide an overview of the proposed Formula. 19

20

A. The Formula, populated with costs for the initial Rate 21

Year, is provided as Exhibit No. TEC-102; it consists of 22

a Table of Contents and 22 schedules. Schedules A-1 and 23

A-2 develop, respectively, (1) the Annual Production 24

Demand Revenue Requirement (“APDRR”) and associated GCC 25


AMENDED: 08/12/2010

11

and (2) the EC (consisting of the fuel and non-fuel 1

variable components). The customer charge is derived on 2

Schedule A-1.1. Schedule A-2.1 provides the calculation 3

of the fuel component (which includes fuel and purchased 4

power) on a monthly basis. In the rate years beginning 5

2011, Schedules A-1 and A-2 will also have true-up 6

amounts that reconcile the prior year’s (or partial 7

year’s) respective revenue requirements to the actual 8

costs supported by the prior-year FERC Form No. 1. The 9

2011 Rate Year true-up amounts will be based on the ratio 10

of the number of months the rate was in effect to 12 11

months, multiplied by the annual difference. This 12

methodology recognizes that the initial rate was in 13

effect for only a partial year. These true-up amounts are 14

converted to rates to enable direct billing or crediting 15

to customers in the succeeding 12 months. The development 16

of the rates on Schedules A-1 and A-2 is supported by 17

numerous worksheets identified as Schedules A-1.1 through 18

A-11. A final schedule, A-12, is the equivalent of 19

Statements BG and BH. After each Annual Update of the 20

Formula, Schedule A-12 will be updated to show the impact 21

on the Tariff customers’ monthly billings resulting from 22

the revised rates. 23

24

In addition to the formulaic development of the GCC and 25


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12

EC, the Implementation Protocols, provided as Attachment 1

B to Tampa Electric’s Tariff, specify (1) the process by 2

which the Company will update the Formula each year, (2) 3

what the review procedures will be, (3) how customer 4

challenges, if any, will be resolved, and (4) how changes 5

to the rates will be implemented. 6

7

Formula Rate in Detail 8

Q. Please describe in further detail the components of the 9

Formula. 10

11

A. Tampa Electric’s proposed Formula develops both the APDRR 12

and the energy costs in the traditional manner. Schedules 13

A-1 and A-2 summarize the calculation of the demand and 14

energy charges, respectively. They include components of 15

return, associated Income Taxes, Taxes Other than Income 16

(“TOI”), Operation and Maintenance (“O&M”) expenses 17

including Administrative and General (“A&G”) expenses 18

functionalized to production, and plant-related 19

Depreciation expense (including General and Intangible 20

(“G&I”) Depreciation and Amortization). The schedules are 21

summed to derive the gross annual revenue requirement. 22

Schedule A-1 provides the demand component, and Schedule 23

A-2 includes the two energy components. Finally, the 24

gross annual revenue requirements for demand costs and 25


AMENDED: 08/12/2010

13

energy costs are adjusted for the appropriate Revenue 1

Credits and transmission losses to obtain the respective 2

net annual revenue requirements. Schedule A-3 calculates 3

a non-levelized Rate Base that is calculated on Net 4

Production Plant and functionalized Net G&I Plant, 5

adjusted for Accumulated Deferred Income Taxes (“ADIT”), 6

Materials and Supplies (“M&S”), Cash Working Capital 7

(“CWC”) and other such Rate Base elements. The Rate Base 8

is multiplied by an overall Rate of Return (“ROR”) to 9

calculate the return component of the annual revenue 10

requirement. 11

12

Q. Please describe the development of Rate Base and the 13

return on Rate Base. 14

15

A. The Rate Base components for both the demand and energy 16

production revenue requirements are detailed on Schedule 17

A-3, lines 1-18. These components are the traditional: 18

Net Plant including functionalized G&I Net Plant, less 19

functionalized ADIT (detailed at Schedule A-4.1), plus 20

Pollution-Control Construction Work in Progress (“CWIP”) 21

(detailed at Schedule A-3.1), plus M&S, functionalized 22

Prepayments (Schedule A-3, lines 19-29), Plant Held for 23

Future Use (detailed at Schedule A-3.2) and CWC. CWC is 24

calculated on Schedule A-3 using the traditionally 25


AMENDED: 08/12/2010

14

accepted method of one-eighth of O&M (including A&G) 1

expense exclusive of fuel and purchased power expense. 2

3

Schedule A-3, calculates Total Rate Base (line 16), along 4

with its demand and energy components. The Rate Base is 5

multiplied by the overall ROR (line 17) to derive the 6

return components of the annual revenue requirements 7

(line 18). These return components are carried over to 8

Schedules A-1 and A-2 as components of the annual demand 9

and energy revenue requirements. 10

11

Q. Please discuss how the Formula develops production O&M 12

expense, including functionalized A&G expense. 13

14

A. Production O&M expense is developed on Schedule A-5 15

combining production cost (by 500 sub-accounts) that have 16

been classified to demand and energy from Schedule A-5.1, 17

lines 1-56, fuel costs and functionalized A&G expense 18

from Schedule A-6, lines 1-12. The following A&G expense 19

adjustments occur prior to being functionalized by Wages 20

and Salaries (“W&S”) to production: (1) Post-retirement 21

Benefits Other than Pensions (“PBOP”) expenses accrued in 22

the year are removed from A&G on line 2 and replaced on 23

line 3 with the amount of actual claims expenses for the 24

year (since the Company does not have an external trust, 25


AMENDED: 08/12/2010

15

Tampa Electric is not proposing to recover the actuarial 1

determined PBOP amounts, but rather only the actual 2

payments made on behalf of retirees for PBOP); (2) 3

Property Insurance expense is removed (line 4) so that 4

Property Insurance unrelated to storm accruals can be 5

allocated separately on plant (line 11); (3) Regulatory 6

Commission expense is removed (line 5), to be replaced by 7

only the directly assigned production Regulatory 8

Commission expenses developed on Schedule A-6.1; (4) 9

General Advertising expense 930.1 (line 6) and any 10

Electric Power Research Institute dues (line 7), if 11

incurred are also removed. The balance of A&G expense 12

(line 8), excluding Property Insurance, is functionalized 13

to production by the W&S Allocator. 14

15

Prior to the calculation of production-related Property 16

Insurance, Tampa Electric will remove any dollars 17

associated with the retail storm accrual. As a result of 18

Tampa Electric’s most recent retail base rate proceeding 19

implemented May 7, 2009, the Company is required to 20

accrue $8 million a year in retail storm damage accruals. 21

In 2009, the accrual amount was $6.7 million because the 22

requirement was in effect from May 7, 2009 through 23

December 31, 2009. Thus when Tampa Electric incurs major 24

storm damages, it reduces the O&M expense in the 500 25


AMENDED: 08/12/2010

16

series accounts and also reduces the storm reserve. Since 1

there is no wholesale storm damage reserve and the retail 2

reserve is for both the distribution and transmission 3

facilities, Tampa Electric proposes to remove the effects 4

of the retail storm damage accruals. This removal is made 5

in Schedule A-6, line 10. However, if Tampa Electric 6

incurs major storm damage, the Company will adjust the 7

production O&M expense for the current year’s impact and 8

remove any prior year’s impact on Schedule A-5.1, lines 9

54 and 55. This will properly apportion the overall 10

production O&M expense to the wholesale customers as they 11

are not participating in the storm accrual costs. 12

13

The overall General Plant W&S Allocator is calculated on 14

Schedule A6, lines 13-17. This allocator is used on 15

several schedules to functionalize items such as G&I 16

Plant (Schedule A-4), A&G expenses (Schedule A-6) and 17

Depreciation expense (Schedule A-7). The model indicates, 18

typically with a footnote, when an allocator is being 19

utilized. The Production W&S Allocator is calculated on 20

the last line on Schedule A-5.1. The calculation is based 21

on FERC standardized methodology for identifying demand 22

and energy. This allocator is typically used for items 23

that are initially functionalized via the General Plant 24

W&S Allocator and then further distributed to demand and 25


AMENDED: 08/12/2010

17

energy based on the Production W&S Allocator. 1

2

Q. Please discuss how Depreciation expense is developed in 3

the Formula. 4

5

A. Depreciation expense is developed on Schedule A-7. 6

Production facilities’ annual Depreciation expense (lines 7

1 through 4) is sourced directly from the FERC Form No. 8

1. Depreciation expense related to Generation Step-up 9

Transformers and the Sebring Acquisition Adjustment are 10

shown on lines 5 and 6. Depreciation expense related to 11

functionalized G&I Plant, shown on line 8, is sourced 12

from the FERC Form No. 1 and functionalized to production 13

by the General Plant W&S Allocator as shown in Note A. 14

The amount functionalized to production is then sub-15

functionalized to demand and energy on the basis of the 16

Production W&S Allocator (Schedule A-7, line 9). 17

Consistent with FERC requirements, Tampa Electric’s 18

depreciation rates for production and general plant (FERC 19

Form No. 1, page 337, year 2007) are itemized on Schedule 20

A-7. These rates will remain fixed until new rates are 21

authorized by FERC subsequent to a filing by Tampa 22

Electric. Consistent with Commission requirements, 23

depreciation rates represent a stated component of the 24

Formula and can only be changed pursuant to a FPA Section 25


AMENDED: 08/12/2010

18

205 or 206 filing. 1

2

Q. Please discuss how the Formula develops TOI. 3

4

A. All TOI functionalized to production are developed on 5

Schedule A-8 (sourced from Tampa Electric’s FERC Form No. 6

1) and are assigned to the generation demand revenue 7

requirement on Schedule A-1, line 4. Schedule A-8, lines 8

1-5, shows that labor-related TOI (FICA and unemployment 9

taxes) are functionalized to production by the labor 10

allocator. Real and Personal Property Taxes are 11

functionalized on the Production Gross Plant Allocator 12

(line 8), as are Other Taxes (lines 7-13). Lines 14-19 13

indicate TOI that are excluded from the Formula, 14

including franchise fees and gross receipts taxes. Total 15

Company TOI reported in Schedule A-8, line 20, will 16

reconcile to the FERC Form No. 1, page 114, line 14. 17

However, the specific line numbers indicated in the 18

Formula template for TOI items are subject to change as 19

tax items are subject to change since page 263 of the 20

FERC Form No. 1 is a free form input page. 21

22

Q. Please discuss the source of the overall ROR noted above. 23

24

A. Schedule A-9 develops the capital structure, debt cost 25


AMENDED: 08/12/2010

19

rate, preferred cost rate (if any) and the overall ROR. 1

The capital amounts – long-term debt (“LTD”), preferred 2

stock and common equity (“CE”) -- shown on lines 1–3 are 3

actual booked amounts reported in the FERC Form No. 1. 4

The LTD cost rate is calculated at lines 10-15, based on 5

FERC Form No. 1 data. The preferred dividend cost rate 6

(if there is preferred outstanding) is calculated at 7

lines 16-17. The CE cost rate (“ROE”) is a fixed number. 8

Initially, it is supported in the filing and, once 9

authorized by FERC, does not change from year-to-year 10

absent a FPA Section 205 or 206 filing for a new FERC-11

authorized ROE. The testimony of Tampa Electric witness 12

Dr. William E. Avera supports the 11.25 percent ROE. 13

14

Q. Please describe the calculation of Income Taxes. 15

16

A. Schedule A-10 calculates the Income Taxes appropriate for 17

the individual demand and energy-related return 18

components. These components roll up to Schedules A-1 and 19

A-2. The composite income tax factor is developed from 20

the applicable marginal federal and state income tax 21

rates (Schedule A-10, lines 14–21). Income Taxes reflect 22

an adjustment for Amortized Investment Tax Credits, as 23

shown at lines 8–13 of Schedule A-10. 24

25


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20

As is apparent from the responses to this and the 1

preceding questions, both the return (including the 2

interest component) on Rate Base and Income Taxes are 3

synchronized to the Rate Base. 4

5

Q. Please discuss the Revenue Credits shown on Schedules A-1 6

and A-2. 7

8

A. The Formula (Schedule A-1, lines 7-13 and A-2, lines 4-8) 9

recognizes certain revenue streams that serve to reduce 10

the component revenue requirements. Generally these are 11

wholesale sales or generation-related services on a 12

short-term or non-firm basis; consequently, the billing 13

determinants of such sales are not included in the loads 14

comprising the production capacity and energy rate 15

divisors on Schedules A-1 and A-2. 16

17

Q. What are sources of the data inputs for the Formula? 18

19

A. The primary source of data for the Formula is the FERC 20

Form No. 1 filed annually at the FERC in April. This is 21

annual cost, financial and operational data for the prior 22

calendar year. Certain data reported in total amounts in 23

the FERC Form No. 1 must be supplemented by detailed 24

components derived from Tampa Electric’s company records 25


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21

and are labeled as such. Examples of these details 1

include components such as ADIT (Schedule 4.1), the Wage 2

and Salary components of production expenses (Schedule 3

5.1, columns 3 and 4), the components of Pollution-4

Control CWIP (Schedule A-3.1), Capital Additions 5

(Schedule A-4.4), and Plant Held for Future Use (“PHFU” – 6

Schedule A-3.2). 7

8

Q. Please describe how the Formula is populated with cost 9

data and the sources of that data. 10

11

A. Developed on an Excel® spreadsheet, each schedule of the 12

Formula consists of numerous lines (rows and column 13

cells) with one of three types of entries: (1) data 14

inputs of “exogenous” data are indicated by shaded cells, 15

accompanied by a description of the source of the data; 16

(2) data inputs that are the result of operations and 17

inputs from a supporting schedule, accompanied by a 18

description of the source-schedule; or (3) the result of 19

a mathematical computation, accompanied by instructions 20

specifying such operation. 21

22

For example, Schedule A-1 – “Determination of Demand-23

Related Costs and Generation Capacity Charges” – consists 24

of 23 lines. Lines 1 through 5, all of which are sourced 25


AMENDED: 08/12/2010

22

from other schedules, are the individual components of 1

the gross demand-related revenue requirement; line 6 is 2

the result of a mathematical operation that sums these 3

components. Lines 7-11 consist of exogenous inputs that 4

are shaded – revenue credits. Line 12 sums all revenue 5

credits, and line 13 directs that these amounts be 6

subtracted from the gross revenue requirement on line 6. 7

Line 14 is exogenous data that is shaded – load data – 8

which are used to calculate the GCC as specified on line 9

15. Line 16 is sourced from another schedule. Line 17 is 10

the result of a mathematical operation that sums lines 15 11

and 16. Line 18 applies the TLF to the GCC and represents 12

the demand rate that will be multiplied by customers’ kW 13

demands to calculate customer bills. Line 19 provides the 14

monthly customer charge, which is sourced from another 15

schedule. Line 20 is the true-up amount, with interest, 16

developed on Schedule A-11. Line 21 is the prior-year 17

load data used to calculate the true-up adjustment rate 18

on line 22. Line 23 is equal to line 22 adjusted for 19

transmission losses to reflect the true-up factor that 20

will be applied to customers’ bills. 21

22

Q. Please discuss how costs are assigned to develop the 23

demand and energy revenue requirements in the Formula. 24

25


AMENDED: 08/12/2010

23

A. Many of the investment components of Rate Base and the 1

cost components of the demand and energy revenue 2

requirements are booked to functionalized accounts. The 3

Formula uses various allocators to distribute the costs, 4

such as the W&S Allocator, the Gross Plant Allocator, and 5

the Net Plant Allocator. Each allocator is calculated 6

within the model and is indicated on the appropriate 7

schedule when it is applied. Other costs are directly 8

assigned. 9

10

For example, production plant Gross Investment, 11

Production Accumulated Depreciation and the associated 12

annual Depreciation are reported as elements of the 13

production function in the FERC Form No. 1 (at pages 204-14

207, 219 and 336, for example). Likewise, production O&M 15

expenses are reported at pages 320-321 of the FERC Form 16

No. 1. 17

18

However, certain other components of Rate Base and 19

expenses must be “functionalized” to production by the 20

standard FERC methodology via allocators based on wages 21

and salaries or plant costs. For example, the majority of 22

the A&G expenses are functionalized to production on the 23

basis of the General Plant W&S Allocator (see Schedule A-24

6, line 17). An exception is Account 924, Property 25


AMENDED: 08/12/2010

24

Insurance, which is functionalized on the basis of Gross 1

Plant (see Schedule A-6, line 11). The Production Gross 2

Plant and Net Plant Allocators are created on Schedule A-3

4. The Production W&S Allocator is based on Schedule A-4

5.1, line 57. It is based on the wages and salaries of 5

production O&M expense for the historical year following 6

the FERC predominance method of classifying O&M expense. 7

8

Similarly, G&I Investment, associated Accumulated 9

Depreciation and annual Depreciation accrual are 10

functionalized on W&S. This is accomplished on Schedule 11

A-4. 12

13

ADIT is functionalized to production through direct 14

assignment, a process that begins with an examination of 15

detailed balances from company records to make any 16

necessary direct assignments, as well as determining when 17

W&S or Plant Allocators are appropriate. This is 18

accomplished on Schedule A-4.1. 19

20

Q. Please discuss the annual process of truing up the 21

charges in effect during the Rate Year with charges 22

calculated based on the corresponding actual FERC Form 23

No. 1 data. 24

25


AMENDED: 08/12/2010

25

A. As I noted earlier, the rate in effect each Rate Year 1

(August 1st through July 31st) will reflect actual costs 2

from the prior calendar year. The 2010 charges proposed 3

in this filing are based on actual 2009 cost data, plus 4

2010 projected capital additions. In 2011, the Formula 5

will be populated with 2010 actual cost data based on the 6

FERC Form No. 1 that includes the 2010 actual capital 7

additions. With the update, the revenue requirements 8

underlying the three rate elements will be recalculated. 9

The difference between the 2009 and 2010 revenue 10

requirements for each of the rate elements is calculated 11

on Schedule A-11, and interest at the FERC published rate 12

will be calculated on a monthly basis and included in the 13

true-up amounts. The revenue requirement for the true-up 14

will be combined with the annual update for calculation 15

of the final rates. These combined rates will be in 16

effect for the next Rate Year, beginning August 1st. For 17

each of the rate elements, these true-ups will be 18

converted to “True-up Adjustment Rates” on Schedules A-1 19

and A-2, based on the prior-year billing determinants to 20

enable Tampa Electric to calculate monthly direct bill 21

amounts to bill customers for the over/(under) collection 22

from the prior year. The 2011 Rate Year “base” revenue 23

requirements for the three rate elements is then 24

calculated by populating the Formula with the 2010 FERC 25


AMENDED: 08/12/2010

26

Form No. 1 actual data plus projected 2011 capital 1

additions. 2

3

Q. How are transmission costs accounted for in the rates? 4

5

A. On Schedule A-12 (Statement BG/BH), Tampa Electric’s firm 6

transmission rate times the monthly capacity billing 7

determinant is calculated as a component of the total 8

monthly revenue requirement. The firm transmission rate 9

is determined in a FERC proceeding independently of the 10

formulaic GCC and, therefore, can change at any time 11

during the Rate Year. The OATT transmission charges are 12

included in the comparison because the service is 13

currently a bundled service. 14

15

Q. In your opinion, is the Formula proposed by Tampa 16

Electric for calculating charges applicable to the 17

service reasonable? 18

19

A. Yes, in my opinion, the proposed Formula is reasonable 20

and consistent with FERC production costing methodologies 21

as reflected in numerous other similar formulas. 22

23

Q. Does this conclude your direct testimony? 24

25


AMENDED: 08/12/2010

27

A. Yes, it does. 1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

DOCKET NO. ER10-2061-000 WITNESS: HEINTZ

28

EXHIBIT

OF

ALAN C. HEINTZ

ON BEHALF OF TAMPA ELECTRIC COMPANY

DOCKET NO. ER10-2061-000 WITNESS: HEINTZ

FILED: 07/30/2010 AMENDED: 08/12/2010

29

Table of Contents

Exhibit No. Title Page

TEC-101 Summary of Testimony Experience 30

TEC-102 Completed Formula – Initial Period Revenue Requirement

40

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30

DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-101WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 1 OF 10

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31


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Illin

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Com

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No.

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39


TAMPA ELECTRIC COMPANY

Power Supply Formula Rate for the Provision of Wholesale Requirements Service

ScheduleSchedule A-1 Determination of Demand-Related Costs and Generation Capacity ChargeSchedule A-1.1 Monthly Customer ChargeSchedule A-2 Determination of Energy-Related Costs and Energy ChargesSchedule A-2.1 Determination of Monthly Energy-Related Costs and Energy ChargesSchedule A-3 Return on Production Related InvestmentSchedule A-3.1 100% Pollution Control Construction Work in Progress (CWIP) and Contract Service Agreements (CSA)Schedule A-3.2 Plant Held for Future UseSchedule A-4 Production-Related Electric Plant in ServiceSchedule A-4.1 Accumulated Deferred Income Taxes (ADIT) WorksheetSchedule A-4.2 Asset Retirement Obligations (ARO)Schedule A-4.3 Generator Step-Up Units (GSU)Schedule A-4.4 Capital Additions Placed in ServiceSchedule A-5 Production Operations & Maintenance (O&M) ExpensesSchedule A-5.1 Classification of Fixed and Variable Production ExpensesSchedule A-6 Production Related Administrative & General Expense Allocation and W&S AllocatorSchedule A-6.1 Regulatory Commission ExpensesSchedule A-7 Production Related Depreciation Expense and Applied Depreciation RatesSchedule A-8 Production Related Taxes Other than Income Taxes (TOI)Schedule A-9 Composite Cost of CapitalSchedule A-10 Production Related Income TaxSchedule A-11 Reconciliation Worksheet Calculation of True-Up Including InterestSchedule A-12 Statement BG/BH

Table of Contents

40


Line Description Notes Reference Demand Related 1 Return on Capital Investment A-3, L18, Col 2 234,035,047 2 Operation & Maintenance Expense (Incl. A&G) A-5, L13, Col 3 212,931,932 3 Depreciation Expense A-7, L11, Col 2 108,627,148 4 Taxes Other than Income Taxes A-8, L19, Col 3 31,850,535 5 Income tax A-10, L7, Col 2 94,638,236 6 Gross Demand Related Revenue Requirement (Sum Lines 1 to 5) 682,082,898

Revenue Credits7 Off-System Sales/Revenue Credits FM-1, p311.h 445,503

Ancillary Service Revenues8 Reactive Supply and Voltage Ancillary Sch 2 399,684 9 Regulation and Frequency Response Ancillary Sch 310 Operating Reserve -- Spinning Ancillary Sch 511 Operating Reserve -- Supplemental Ancillary Sch 612 Subtotal Revenue Credits (Sum Lines 7 to 11) 845,187

13 Annual Production Demand Revenue Requirement (APDRR) L6 - L12 681,237,711

14 Total 12 Months System Peaks Sum FM-1, p401b.d 40,952 MW15 Generation Capacity Charge (per kW/month) (L13 / L14) / 1000 $16.64/kW16 Plus Production Regulatory Commission Expenses A-6.1, L50 $0.01/kW17 Sum Total L15 + L16 $16.65/kW

18 Generation Capacity Charge ("GCC") (per kW/month) (adjusted by TLF) a/ L17 /TLF $16.91/kW

19 Proposed Monthly Customer Charge A-1.1, L6 500$

20 True-up Adjustment -- Amount A-11, L35, Col f - 21 Prior-year 12 Monthly System Peaks FM-1, p401b.d 0 MW22 True-up Adjustment Rate (L20 / L21)/ 1000 $0.00/kW23 True-up Adjustment Rate (adjusted by TLF) a/ (L22 /TLF ) $0.00/kW

Notes:a/ Transmission Loss Factor (TLF) A-2, Note b/4 0.9842

Schedule A-1 Determination of Demand-Related Costs and Generation Capacity ChargeTwelve Months Ended December 31, 2009 -- Actual


41


Line Description Reference Amount1 Annual Salary & Benefits Company Records 312,724$

2 % Time on Requirements Customers Support & Billing Company Records 10%

3 Annual Cost (L1 * L2) 31,272$

4 Monthly Cost (L3 / 12 months) 2,606$

5 Existing Requirements Customers (L4 / # of customers) 869$

6 Proposed Customer Charge 500$

Note: The Customer Charge is calculated based on 2009 salary information. It will remain fixed and can only be changed through a FPA Section 205 or 206 rate filing at FERC.


Schedule A-1.1 Monthly Customer Charge Twelve Months Ended December 31, 2009 -- Actual

42



Line Description Notes Reference Energy Related Fuel & Purchased Power Charge

1 Total Fuel A-5, L12, Col 5 839,112,299 2 Purchased Power (PP) A-5, L1, Col 5 81,410,745 3 Subtotal Fuel & Purchased Power Charge L1 + L2 920,523,044

Revenue Credits4 Off-System Sales/Revenue Credits a/ 13,256,531 5 Ancillary Service Revenues6 Energy Imbalance Service Ancillary Sch. 4 - 7 Generator Imbalance Service Ancillary Sch 9 - 8 Subtotal Revenue Credits (Sum Lines 4 to 7) 13,256,531

9 Subtotal Fuel & PP less Revenue Credits L3 - L8 907,266,513

Non-Fuel Variable Cost Energy Charge 10 Non-Fuel Energy Production O&M Expense (incl. A&G) A-5, L13, Col 4 88,471,438 11 Return on Rate Base A-3, L18, Col 3 10,438,671 12 Depreciation Expense A-7, L11, Col 3 3,389,647 13 Income Tax A-10, L7, Col 3 4,220,371 14 Total Non-Fuel Variable Cost Energy Charge (Sum Lines 10 to 13) 106,520,128

15 Total Energy less Non-Requirements Sales for Resale FM-1, p401b.41.b - .41c 19,976,247 MWh

16 Non-Fuel Variable Cost Energy Charge L14 / L15 / 1000 $0.00533/kWh17 Fuel and Purchased Power Charge L9 / L15 / 1000 $0.04542/kWh18 Energy Charge (per kwh) L16 + L17 $0.05075/kWh

19 Non-Fuel Variable Cost Energy Charge ("NFVC") (Adjusted by TLF) b/ L16 / TLF $0.00542/kWh20 Fuel and Purchased Power Charge ("FPPC") (Adjusted by TLF) b/ L17 / TLF $0.04615/kWh21 Energy Charge ("EC") (per kWh) (Adjusted by TLF) L19 + L20 $0.05156/kWh

22 True-up Adjustment Amount A-11, L35, Cols. i + l - 23 Prior-Year Net MWh generated and purchased, less MWh sold FM-1, p401b.41.b - .41.c 0 MWh24 True-up Adjustment Rate (per kWh) (L22/L23)/1000 $0.00000/kWh

25 True-up Adjustment Rate (per kWh) (Adjusted by TLF) b/ (L24 /TLF ) $0.00000/kWh

Notes:a/ Revenue credits are associated with fuel, margins & variable O&M dollars included in FM-1, pg 311. i

b/ System Average Transmission Losses (based on FERC Annual A/B Filing, Schedule C):1)Transmission System Losses, incl Generator Step-UpTransformer Losses 365,829 2) Total Annual Energy Output to Line Composed of: Total of all EnergyAvailable, plus Wheeling Rec'd, less Wheeling Del'd Losses 23,186,308 3) System Average Transmission Loss Percentage ((Note b L1/L2)*100) 1.58 4) Transmission Loss Factor (TLF) ((100 - Note b L3)/100) 0.9842

Schedule A-2 Determination of Energy-Related Costs and Energy ChargesTwelve Months Ended December 31, 2009 -- Actual

43


Line Description Notes Reference Energy

Fuel & Purchased Power Charge1 555 Purchased Power (PP) a/, b/ FM-1, p327.m 2 501 Fuel a/ FM-1, p320.5.b 3 518 Fuel a/ FM-1, p320.25.b 4 547 Fuel a/ FM-1, p321.63.b 5 Subtotal Fuel & Purchased Power Charge (Sum Lines 1 to 4) -

Revenue Credits6 Off-System Sales/Revenue Credits c/ FM-1,p311.i - 7 Ancillary Service Revenues8 Energy Imbalance Service Ancillary Sch. 4 - 9 Generator Imbalance Service Ancillary Sch 9 -

10 Subtotal Revenue Credits (Sum Lines 6 to 9) -

11 Subtotal Fuel & PP less Revenue Credits e/ L5 - L10 -

12 Total Energy less Non-Requirements Sales for Resale a/ FM-1, p401b.41.b - 41.c 0 MWh

13 Fuel & Purchased Power Charge ($/kWh) (L11 / L12) / 1000 $0.0000/kWh

14 d/ (L13/TLF) $0.0000/kWh

Notes:a/ Reference is to FERC Form No. 1, which is annual. The amounts on this schedule are monthly. They will tie to annual totals by year end, except

for true-ups or adjustments.b/ 555 Purchased Power (FM-1, p327). The "Other" component is classified to demand or non-fuel energy dependent on source.c/ Reference is to FERC Form No. 1, which is annual. The amounts on this schedule are monthly. The credits will include fuel, margins, &

variable O&M when applicable.d/ The Transmission Loss Factor (TLF), Schedule A-2, is reported annually in Tampa Electric's FERC A/B Filing, Schedule C and will be updated

in the Annual Update Process.e/ Prior Period Adjustments will be included when applicable.

Total Demand Other: Classified

as Demand Other:Classified

as Non-Fuel Energy Energy

Line Description Reference (a) (b) (c) (d) (e)Company InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany Invoices

Add additional invoices as necessary.

Total Sum Invoices - - - - -

Monthly Detail, Purchased Power

Schedule A-2.1 Determination of Monthly Energy-Related Costs and Energy Charges


Month of _____________

Fuel & Purchased Power Charge ("FPPC") ($/kWh) (Adjusted by TLF)

44



Production Total Demand Energy

Line Description Notes Reference (1) (2) (3)

Electric Plant1 Gross Plant in Service (incl. G&I) A-4, L6, Col 2 - 4 3,906,476,047 3,865,753,042 40,723,005 2 Accumulated Depreciation (incl. G&I) A-4, L13, Col 2 - 4 (1,203,871,685) (1,185,424,756) (17,504,500) 3 Accumulated Deferred Taxes A-4, L16, Col 2 - 4 (221,312,562) (219,488,404) (1,901,332) 4 Net Plant in Service L1 + L2 + L3 2,481,291,801 2,460,839,882 21,317,174 5 Construction Work in Progress a/ A-3.1, L3, Col 2 65,168,809 65,168,809 - 6 Subtotal - Electric Plant L4 + L5 2,546,460,610 2,526,008,690 21,317,174

7 Materials & Supplies8 Fuel Inventory FM-1 p227.1.c 85,823,389 - 85,823,389 9 Non-fuel Production FM-1 p227.7.c 24,535,944 24,535,944 -

10 Prepayments b/ L29 5,842,711 5,842,711 - 11 CSA A-3.1, L12, Col 2 65,277,680 65,277,680 - 12 Plant Held for Future Use A-3.2, L1 1,738,162 1,738,162 - 13 Subtotal Electric Plant (Sum Lines 6 to 12) 2,729,678,496 2,623,403,188 107,140,563 14 O&M (excl. Fuel & Purchased Power) A-5, L7 - A-5, L1 258,257,253 120,783,258 84,356,554 15 Cash Working Capital on O&M 1/8 * L14 32,282,157 15,097,907 10,544,569 16 Total Rate Base L13 + L15 2,761,960,653 2,638,501,096 117,685,132 17 Composite Cost of Capital A-9, L4, Col 4 8.87% 8.87% 8.87%18 Return on Rate Base L16 * L17 244,985,910 234,035,047 10,438,671

19 Total Prepaids FM-1 p111.57.c 10,425,275 20 Less Acct 16518 Prepaid Ammonia Supply Line (BB SCR's) Company Records 3,004,800 21 Less Acct 16552 Prepaid Water (BB4 FGD) Company Records 206,925 22 Less Sum of Acct 16570:16581 (LTSA & CSA) Company Records 2,162,983 23 Subtotal Non-Production Prepaids L19 - L20 - L21 - L22 5,050,567 24 General Plant W&S Allocator A-6, L17, Col 1 52.09%25 Subtotal of Allocated Non-Production Prepaids L23 * L24 2,630,986 26 Plus Direct Production Prepaids27 Acct 16518 Prepaid Ammonia Supply Line (BB SCR's) L20 3,004,800 28 Acct 16552 Prepaid Water (BB4 FGD) L21 206,925 29 Total Production Prepayments L25 + L27 + L28 5,842,711

Notes:a/ Production amount only - major 100% Pollution Control Projects, A-3.1. b/ Prepayments classified and functionalized using W&S Allocator.

Calculation of Production Prepaids:

Schedule A-3 Return on Production-Related InvestmentTwelve Months Ended December 31, 2009 -- Actual

45


CWIP Amount DemandLine Project Name/Description Reference (1) (2)

Pollution Control CWIP1 L91 - Big Bend SCR Unit 1 Company Records 71,219,830 2 Less AFUDC Company Records 6,051,022

3 Net Total Pollution Control CWIP L 1 - L2 65,168,809

Contract Service Agreements (CSA)4 Bayside 1 Company Records 15,592,402 5 Bayside 2 Company Records 13,325,206 6 Polk 1 Company Records 13,508,411 7 Polk 2 Company Records 4,788,545 8 Polk 3 Company Records 10,606,377 9 Polk 4 Company Records 3,468,679 10 Polk 5 Company Records 2,530,951 11 Polk 4&5 Spares Company Records 1,457,109 12 Total Contract Service Agreements (CSA) (Sum Lines 4 to 11) 65,277,680

Schedule A-3.1 100% Pollution Control Construction Work in Progress (CWIP) and Contract Service Agreements (CSA)Twelve Months Ended December 31, 2009 -- Actual


46



Line Description Reference Demand1 Production (Land in Fee) Company Records 1,738,162$

2 Transmission (Land in Fee) Company Records 30,281,108 3 Distribution (Land in Fee) Company Records 5,722,590 4 Subtotal - Transm. & Distribution 36,003,698

5 General (Land in Fee) Company Records -

6 Total Plant Held for Future Use L1 + L4 + L5 37,741,860$

Schedule A-3.2 Plant Held for Future UseTwelve Months Ended December 31, 2009 -- Actual

47



ProductionSystem Total Demand Energy

Line Description Notes Reference (1) (2) (3) (4)Gross Plant in Service

1 Electric Plant in Service (excl. G&I & GSU's) FM-1, p207.104.g

Less (L3 + L4) 5,807,839,134 3,540,416,676 3,540,416,676 -

2 Capital Additions d/ A-4.4, L13 218,052,961 218,052,961 218,052,961 -

3 Generator Step-Up Units (GSU) A-4.3, L9 40,550,349 40,550,349 40,550,349 -

4 General & Intangible a/, b/ FM-1, p205.5.g + p207.99.g 213,377,902 111,154,717 69,030,019 42,124,698

5 Less Asset Retirement Obligations (ARO) a/, b/ A-4.2, L6 7,100,117 3,698,656 2,296,963 1,401,693

6 Total Adjusted Gross Plant L1 + L2 + L3 + L4 - L5 6,272,720,229 3,906,476,047 3,865,753,042 40,723,005

7 Gross Plant Allocator L6 / L6 100.00% 62.28% 61.63% 0.65%

Accumulated Depreciation & Amortization

8 Electric Plant in Service (excl. G&I & GSU's) e/ FM-1, p200.18.c

Less (L9 + L10+ L11) 1,994,829,801 1,147,608,892 1,147,608,892 -

9 Generator Step-Up Units (GSU) A-4.3, L18 10,073,555 10,073,555 10,073,555 -

10 General Plant a/, b/ FM-1, p219.28.c 82,031,305 42,732,478 26,537,999 16,194,479

11 Amort. of Other Utility Plant (Intangible) a/, b/ FM-1, p200.21.c 7,474,119 3,893,485 1,475,528 1,475,528

12 Less Asset Retirement Obligations (ARO) a/, b/ A-4.2, L13, Col 1 838,358 436,725 271,218 165,507

13 Total Adjusted Accum. Deprec. & Amortization L8 + L9 + L10 + L11 - L12 2,093,570,422 1,203,871,685 1,185,424,756 17,504,500

14 Net Plant L6 - L13 4,179,149,807 2,702,604,363 2,680,328,286 23,218,506

15 Net Plant Allocator L14 / L14 100.00% 64.67% 64.14% 0.56%16 Accumulated Deferred Taxes c/ A-4.1, L9, Col 4 (342,224,842) (221,312,562) (219,488,404) (1,901,332)

Notes:a/ Production is functionalized based on General Plant W&S Allocator, A-6, L 17. 52.09%b/ Production is further functionalized between Demand and Energy based on Production W&S Allocator, A-5.1, L57

Production Demand 62.10%Production Energy 37.90%

c/ ADIT is functionalized on Schedule 4.1 and allocated to demand and energy based on the net plant ratio.d/ Capital Additions will not be included in true-up calculations.e/ Production Accumulated Reserve is based on Production only, FM-1, p 219, L20 + L24, col c.

Schedule A-4 Production-Related Electric Plant in ServiceTwelve Months Ended December 31, 2009 -- Actual

48


TAMP

A EL

ECTR

IC C

OMPA

NY

Tota

lG

ener

atio

nPl

ant

Labo

rG

ener

atio

nLi

neD

escr

iptio

nR

efer

ence

Rel

ated

Rel

ated

Rel

ated

ADIT

(1)

(2)

(3)

(4)

(5)

(6)

(7)

1AD

IT- 2

82Sc

h. 2

82, B

elow

(409

,234

,318

)0

(19,

182,

858)

2AD

IT-2

83Sc

h. 2

83, B

elow

(11,

142,

606)

(4,0

09,2

80)

14,1

82,7

493

ADIT

-190

Sch.

190

, Bel

ow88

,484

,972

12,7

08,7

911,

926,

869

4AD

IT-2

81Sc

h. 2

81, B

elow

(14,

149,

764)

00

5Su

btot

al A

DIT

Sum

Lin

es (1

to 4

)(3

46,0

41,7

16)

8,69

9,51

1(3

,073

,240

)6

Wag

es &

Sal

ary

Allo

cato

rSc

hedu

le A

-6,L

17, C

ol 1

52.0

9%7

Gro

ss P

lant

Allo

cato

rSc

hedu

le A

-4, L

7, C

ol 2

62.2

8%8

Sub-

tota

l L

ine

5 *

Allo

cato

r(3

46,0

41,7

16)

5,41

7,81

4(1

,600

,940

)9

Tota

l Pro

duct

ion

ADIT

Sum

Col

s. (4

to 6

)(3

42,2

24,8

42)

Ente

r as

nega

tive

Sche

dule

4, L

ine

16

In fi

lling

out

this

atta

chm

ent,

a fu

ll an

d co

mpl

ete

desc

riptio

n of

eac

h ite

m a

nd ju

stifi

catio

n fo

r the

allo

catio

n to

Col

umns

B-F

and

eac

h se

para

te A

DIT

item

will

be

liste

d,di

ssim

ilar i

tem

s w

ith a

mou

nts

exce

edin

g $1

00,0

00 w

ill b

e lis

ted

sepa

rate

ly.

Sche

dule

AD

IT -

190

Gas

, Tra

ns.,

Tota

lD

ist O

r Oth

erG

ener

atio

nPl

ant

Labo

rD

escr

iptio

nFo

rm 1

Ref

eren

ceC

ompa

nyR

elat

edR

elat

edR

elat

edR

elat

edJu

stifi

catio

nA

BC

DE

FG

Acco

unt 1

90

Cap

italiz

ed In

tere

st-P

rodu

ctio

n Pl

ant

32,1

23,5

4632

,123

,546

Pro

duct

ion

Plan

t rel

ated

263

(A)f

inte

rest

exp

ense

attr

ibut

able

to th

e co

st o

f con

stru

ctin

g an

ass

et is

not

cu

rren

tly d

educ

tible

; rat

her,

it m

ust b

e ca

pita

lized

and

add

ed to

the

basi

s of

the

asse

t.

Cap

italiz

ed In

tere

st-D

istri

butio

n12

,168

,010

12,1

68,0

10 D

istri

butio

n re

late

d 26

3(A)

f int

eres

t exp

ense

attr

ibut

able

to th

e co

st o

f con

stru

ctin

g an

ass

et is

not

cu

rren

tly d

educ

tible

; rat

her,

it m

ust b

e ca

pita

lized

and

add

ed to

the

basi

s of

the

asse

t.

Cap

italiz

ed In

tere

st-T

rans

mis

sion

4,38

0,48

44,

380,

484

Tra

nsm

issi

on re

late

d 26

3(A)

f int

eres

t exp

ense

attr

ibut

able

to th

e co

st o

f con

stru

ctin

g an

ass

et is

not

cu

rren

tly d

educ

tible

; rat

her,

it m

ust b

e ca

pita

lized

and

add

ed to

the

basi

s of

the

asse

t.

CIA

C32

,287

,264

32,2

87,2

64 T

rans

mis

sion

& D

istri

butio

n re

late

d in

com

e th

at is

taxa

ble

for t

ax re

turn

pur

pose

s, b

ut re

cord

ed a

s a

redu

ctio

n to

pla

nt fo

r boo

k pu

rpos

es.

Def

erre

d D

eriva

tive

11,2

13,6

7111

,213

,671

Def

erre

d bo

ok e

xpen

se n

ot d

educ

ted

for t

ax r

etur

n pu

rpos

es re

late

d to

unr

ealiz

ed d

eriva

tives

offs

et

with

def

erre

d lia

bilit

y D

ism

antli

ng44

,883

,178

44,8

83,1

78 A

ccru

ed p

rodu

ctio

n pl

ant d

ism

antli

ng b

ook

expe

nse

not d

educ

ted

for t

ax r

etur

n pu

rpos

es

Early

Cap

acity

Pay

men

ts26

4,57

726

4,57

7 D

efer

red

book

exp

ense

not

ded

ucte

d fo

r tax

ret

urn

purp

oses

Accu

mul

ated

Def

erre

d In

vest

men

t Tax

Cre

dit

4,05

3,83

34,

053,

833

Bas

is d

iffer

ence

bet

wee

n bo

ok a

nd ta

x pl

ant b

asis

rela

ted

to in

vest

men

t tax

cre

dit o

n pr

oduc

tion

prop

erty

Accu

mul

ated

Def

erre

d In

vest

men

t Tax

Cre

dit

2,08

8,33

82,

088,

338

Bas

is d

iffer

ence

bet

wee

n bo

ok a

nd ta

x pl

ant b

asis

rela

ted

to in

vest

men

t tax

cre

dit o

n tra

nsm

issi

on &

di

strib

utio

n pr

oper

ty

FAS

158-

Pens

ion

58,8

04,6

8658

,804

,686

Ass

et re

cord

ed fo

r reg

ulat

ory

purp

oses

for F

AS 1

58 p

ensi

on a

nd p

ost-r

etire

men

t cos

ts

FAS

158-

SER

P66

5,96

366

5,96

3 A

sset

reco

rded

for r

egul

ator

y pu

rpos

es fo

r FAS

158

pen

sion

and

pos

t-ret

irem

ent c

osts

FA

S 15

8-FA

S106

18,3

67,9

3218

,367

,932

Ass

et re

cord

ed fo

r reg

ulat

ory

purp

oses

for F

AS 1

58 p

ensi

on a

nd p

ost-r

etire

men

t cos

ts

Insu

ranc

e R

eser

ve-S

torm

11,3

09,7

7711

,309

,777

Acc

rued

insu

ranc

e re

serv

e bo

ok e

xpen

se n

ot d

educ

ted

for t

ax r

etur

n pu

rpos

es

Insu

ranc

e R

eser

ve-I&

D10

,161

,972

10,1

61,9

72 A

ccru

ed in

sura

nce

rese

rve

book

exp

ense

not

ded

ucte

d fo

r tax

ret

urn

purp

oses

Inte

rest

Rat

e Sw

ap2,

546,

819

2,54

6,81

9 D

efer

red

book

exp

ense

not

ded

ucte

d fo

r tax

ret

urn

purp

oses

rela

ted

to d

eriva

tive

inte

rest

rate

sw

aps

Def

erre

d Le

ase

1,26

0,90

61,

260,

906

Def

erre

d Le

ase

book

exp

ense

not

ded

ucte

d fo

r tax

ret

urn

purp

oses

Add

add

ition

al li

nes

if ne

cess

ary.

Su

btot

al -

190

p234

.18.

c24

6,58

0,95

613

9,40

6,49

192

,538

,805

12,7

08,7

911,

926,

869

Less

FAS

B 1

09 A

bove

if n

ot s

epar

atel

y re

mov

ed6,

142,

171

2,08

8,33

84,

053,

833

Less

FAS

B 1

06 A

bove

if n

ot s

epar

atel

y re

mov

ed18

,367

,932

18,3

67,9

32To

tal

222,

070,

853

118,

950,

221

88,4

84,9

7212

,708

,791

1,92

6,86

9

Inst

ruct

ions

for A

ccou

nt 1

90:

2. A

DIT

item

s re

late

d on

ly to

Pro

duct

ion

are

dire

ctly

ass

igne

d to

Col

umn

D.

3. A

DIT

item

s re

late

d to

Pla

nt a

nd n

ot in

Col

umns

C &

D a

re in

clud

ed in

Col

umn

E.

4. A

DIT

item

s re

late

d to

labo

r and

not

in C

olum

ns C

& D

are

incl

uded

in C

olum

n F.

Sche

dule

A-4

.1 A

ccum

ulat

ed D

efer

red

Inco

me

Taxe

s (A

DIT

) Wor

kshe

etTw

elve

Mon

ths

Ende

d D

ecem

ber 3

1, 2

009

-- A

ctua

l

Acc

umul

ated

Def

erre

d In

com

e Ta

xes

(AD

IT) W

orks

heet

6. G

ener

al P

lant

item

s w

ill be

allo

cate

d on

a la

bor r

atio

.

1. A

DIT

item

s re

late

d on

ly to

Non

-Ele

ctric

Ope

ratio

ns (e

.g.,

Gas

, Wat

er, S

ewer

) or T

rans

mis

sion

are

dire

ctly

ass

igne

d to

Col

umn

C.

5. D

efer

red

inco

me

taxe

s ar

ise

whe

n ite

ms

are

incl

uded

in ta

xabl

e in

com

e in

diff

eren

t per

iods

than

they

are

incl

uded

in ra

tes,

ther

efor

e if

the

item

giv

ing

rise

to th

e A

DIT

is n

ot

incl

uded

in th

e fo

rmul

a, th

e as

soci

ated

AD

IT a

mou

nt s

hall

be e

xclu

ded.

49


Sche

dule

AD

IT -

281

Gas

, Tra

ns.,

Tota

lD

ist O

r Oth

erG

ener

atio

nPl

ant

Labo

rD

escr

iptio

nFo

rm 1

Ref

eren

ceC

ompa

nyR

elat

edR

elat

edR

elat

edR

elat

edJu

stifi

catio

nA

BC

DE

FG

Acco

unt 2

81Ac

cele

rate

d Am

ortiz

atio

n(1

4,14

9,76

4)(1

4,14

9,76

4) C

ertif

ied

pollu

tion

cont

rol f

acilit

ies

as p

erm

itted

by

Sect

ion

169

of th

e In

tern

al R

even

ue C

ode.

Add

add

ition

al li

nes

if ne

cess

ary.

Subt

otal

- 28

1p2

73.1

7.k

(14,

149,

764)

0(1

4,14

9,76

4)0

0Le

ss F

ASB

109

Abo

ve if

not

sep

arat

ely

rem

oved

Less

FAS

B 1

06 A

bove

if n

ot s

epar

atel

y re

mov

ed0

Tota

l(1

4,14

9,76

4)0

(14,

149,

764)

00

Inst

ruct

ions

for A

ccou

nt 2

81:

2. A

DIT

item

s re

late

d on

ly to

Pro

duct

ion

are

dire

ctly

ass

igne

d to

Col

umn

D.

3. A

DIT

item

s re

late

d to

Pla

nt a

nd n

ot in

Col

umns

C &

D a

re in

clud

ed in

Col

umn

E.

4. A

DIT

item

s re

late

d to

labo

r and

not

in C

olum

ns C

& D

are

incl

uded

in C

olum

n F.

Sche

dule

AD

IT -

282

Gas

, Tra

ns.,

Tota

lD

ist O

r Oth

erG

ener

atio

nPl

ant

Labo

rD

escr

iptio

nFo

rm 1

Ref

eren

ceC

ompa

nyR

elat

edR

elat

edR

elat

edR

elat

edJu

stifi

catio

nA

BC

DE

FG

Acco

unt 2

82

Dep

reci

atio

n-Pr

oduc

tion

(348

,349

,727

)(3

48,3

49,7

27)

Ded

uctio

ns fo

r pro

duct

ion

plan

t rel

ated

to ta

x de

prec

iatio

n in

exc

ess

of b

ook

depr

ecia

tion

at fe

dera

l ra

te

Dep

reci

atio

n-D

istri

butio

n(1

30,6

31,1

48)

(130

,631

,148

) D

educ

tions

for d

istri

butio

n re

late

d to

tax

depr

ecia

tion

in e

xces

s of

boo

k de

prec

iatio

n at

fede

ral r

ate

Dep

reci

atio

n-Tr

ansm

issi

on(4

8,98

6,68

0)(4

8,98

6,68

0) D

educ

tions

for t

rans

mis

sion

rela

ted

to ta

x de

prec

iatio

n in

exc

ess

of b

ook

depr

ecia

tion

at fe

dera

l rat

e

Dep

reci

atio

n-G

ener

al P

lant

(16,

328,

893)

(16,

328,

893)

Ded

uctio

ns fo

r gen

eral

pla

nt re

late

d to

tax

depr

ecia

tion

in e

xces

s of

boo

k de

prec

iatio

n at

fede

ral r

ate

FAS

109

regu

lato

ry a

sset

s/lia

bilit

ies

rela

ted

to p

lant

(21,

836,

522)

(21,

836,

522)

Ass

ets

reco

rded

for r

egul

ator

y pu

rpos

es to

adj

ust p

rodu

ctio

n pl

ant r

elat

ed d

efer

red

taxe

s to

cur

rent

fe

dera

l and

sta

te ra

tes

FAS

109

regu

lato

ry a

sset

s/lia

bilit

ies

rela

ted

to p

lant

(11,

259,

457)

(11,

259,

457)

Ass

ets

reco

rded

for r

egul

ator

y pu

rpos

es to

adj

ust t

rans

mis

sion

& d

istri

butio

n re

late

d de

ferr

ed ta

xes

to

curr

ent f

eder

al a

nd s

tate

rate

s

FAS

109

regu

lato

ry a

sset

s/lia

bilit

ies

rela

ted

to p

lant

(1,0

23,5

87)

(1,0

23,5

87)

Ass

ets

reco

rded

for r

egul

ator

y pu

rpos

es to

adj

ust p

lant

rela

ted

defe

rred

taxe

s to

cur

rent

fede

ral a

nd

stat

e ra

tes

Cos

t of R

emov

al-P

rodu

ctio

n(6

0,88

4,59

1)(6

0,88

4,59

1) D

educ

tions

for r

emov

al c

ost r

elat

ed to

pro

duct

ion

Cos

t of R

emov

al -T

rans

mis

sion

& D

istri

butio

n(3

1,39

3,61

7)(3

1,39

3,61

7) D

educ

tions

for r

emov

al c

ost r

elat

ed to

tran

smis

sion

& d

istri

butio

n C

ost o

f Rem

oval

-Gen

eral

Pla

nt(2

,853

,965

)(2

,853

,965

) D

educ

tions

for r

emov

al c

ost r

elat

ed to

gen

eral

pla

nt

Add

add

ition

al li

nes

if ne

cess

ary.

Su

btot

al -

282

p275

.9.k

(673

,548

,187

)(2

22,2

70,9

02)

(431

,070

,840

)(1

,023

,587

)(1

9,18

2,85

8)Le

ss F

ASB

109

Abo

ve if

not

sep

arat

ely

rem

oved

(34,

119,

566)

(11,

259,

457)

(21,

836,

522)

(1,0

23,5

87)

Less

FAS

B 1

06 A

bove

if n

ot s

epar

atel

y re

mov

ed0

Tota

l(6

39,4

28,6

21)

(211

,011

,445

)(4

09,2

34,3

18)

0(1

9,18

2,85

8)

Inst

ruct

ions

for A

ccou

nt 2

82:

2. A

DIT

item

s re

late

d on

ly to

Pro

duct

ion

are

dire

ctly

ass

igne

d to

Col

umn

D.

3. A

DIT

item

s re

late

d to

Pla

nt a

nd n

ot in

Col

umns

C &

D a

re in

clud

ed in

Col

umn

E.

4. A

DIT

item

s re

late

d to

labo

r and

not

in C

olum

ns C

& D

are

incl

uded

in C

olum

n F.

6. G

ener

al P

lant

item

s w

ill be

allo

cate

d on

a la

bor r

atio

.

5. D

efer

red

inco

me

taxe

s ar

ise

whe

n ite

ms

are

incl

uded

in ta

xabl

e in

com

e in

diff

eren

t per

iods

than

they

are

incl

uded

in ra

tes,

ther

efor

e if

the

item

giv

ing

rise

to th

e A

DIT

is n

ot

incl

uded

in th

e fo

rmul

a, th

e as

soci

ated

AD

IT a

mou

nt s

hall

be e

xclu

ded.

6. G

ener

al P

lant

item

s w

ill be

allo

cate

d on

a la

bor r

atio

.

1. A

DIT

item

s re

late

d on

ly to

Non

-Ele

ctric

Ope

ratio

ns (e

.g.,

Gas

, Wat

er, S

ewer

) or T

rans

mis

sion

are

dire

ctly

ass

igne

d to

Col

umn

C.

5. D

efer

red

inco

me

taxe

s ar

ise

whe

n ite

ms

are

incl

uded

in ta

xabl

e in

com

e in

diff

eren

t per

iods

than

they

are

incl

uded

in ra

tes,

ther

efor

e if

the

item

giv

ing

rise

to th

e A

DIT

is n

ot

incl

uded

in th

e fo

rmul

a, th

e as

soci

ated

AD

IT a

mou

nt s

hall

be e

xclu

ded.

Sche

dule

A-4

.1 A

ccum

ulat

ed D

efer

red

Inco

me

Taxe

s (A

DIT

) Wor

kshe

etTw

elve

Mon

ths

Ende

d D

ecem

ber 3

1, 2

009

-- A

ctua

l

TAM

PA E

LEC

TRIC

CO

MPA

NY

1. A

DIT

item

s re

late

d on

ly to

Non

-Ele

ctric

Ope

ratio

ns (e

.g.,

Gas

, Wat

er, S

ewer

) or T

rans

mis

sion

are

dire

ctly

ass

igne

d to

Col

umn

C.

50


Sche

dule

AD

IT -

283

Gas

, Tra

ns.,

Tota

lD

ist O

r Oth

erG

ener

atio

nPl

ant

Labo

rD

escr

iptio

nFo

rm 1

Ref

eren

ceC

ompa

nyR

elat

edR

elat

edR

elat

edR

elat

edJu

stifi

catio

nA

BC

DE

FG

Acco

unt 2

83

Gai

n on

Sal

e of

Lan

d - P

rodu

ctio

n89

,700

89,7

00 D

efer

red

cred

it re

late

d to

am

ortiz

atio

n of

sal

e of

land

hel

d fo

r fut

ure

use

not d

educ

tible

on

tax

retu

rn

Gai

n on

Sal

e of

Lan

d-D

istri

butio

n29

7,53

229

7,53

2 D

efer

red

cred

it re

late

d to

am

ortiz

atio

n of

sal

e of

land

hel

d fo

r fut

ure

use

not d

educ

tible

on

tax

retu

rn

Gai

n on

Sal

e of

Lan

d-G

ener

al9,

365

9,36

5 D

efer

red

cred

it re

late

d to

am

ortiz

atio

n of

sal

e of

land

hel

d fo

r fut

ure

use

not d

educ

tible

on

tax

retu

rn

Gai

n on

Sal

e of

Lan

d-Tr

ansm

issi

on67

7,89

467

7,89

4 D

efer

red

cred

it re

late

d to

am

ortiz

atio

n of

sal

e of

land

hel

d fo

r fut

ure

use

not d

educ

tible

on

tax

retu

rn

Unb

illed

Rev

enue

17,4

91,6

5617

,491

,656

Ret

ail r

elat

ed in

com

e th

at is

taxa

ble

for t

ax re

turn

pur

pose

s an

d de

ferr

ed fo

r boo

k pu

rpos

es.

37,3

55,2

4337

,355

,243

Em

ploy

ers'

Acc

ount

ing

for P

ostre

tirem

ent B

enef

its O

ther

Tha

n Pe

nsio

ns n

ot d

educ

tible

for t

ax

purp

oses

5,58

8,39

05,

588,

390

Em

ploy

ers'

Acc

ount

ing

for P

oste

mpl

oym

ent B

enef

its n

ot d

educ

tible

for t

ax re

turn

pur

pose

s

(22,

392,

266)

(22,

392,

266)

Pen

sion

acc

rued

exp

ense

for b

ook

purp

oses

not

ded

uctib

le fo

r tax

pur

pose

s

6,48

1,98

56,

481,

985

Boo

k ex

pens

e no

t ded

uctib

le fo

r tax

pur

pose

s - l

abor

rela

ted

to a

ll fu

nctio

ns

(8)

(8)

Boo

k ex

pens

e no

t ded

uctib

le fo

r tax

pur

pose

s

(18,

820,

538)

(18,

820,

538)

Ret

ail D

efer

red

Fuel

Und

er R

ecov

ery

dedu

ctib

le fo

r tax

pur

pose

s

(2,8

31,3

12)

(2,8

31,3

12)

Bon

d R

efin

anci

ng In

tere

st b

ook

expe

nse

dedu

ctib

le fo

r tax

pur

pose

s

(447

,390

)(4

47,3

90)

Bon

d R

efin

anci

ng C

all P

rem

ium

boo

k ex

pens

e de

duct

ible

for t

ax p

urpo

ses

1,25

8,20

01,

258,

200

Bon

d R

efin

anci

ng P

ut O

ptio

n bo

ok e

xpen

se n

ot d

educ

tible

for t

ax p

urpo

ses

3,15

1,68

83,

151,

688

Boo

k ex

pens

e no

t ded

uctib

le fo

r tax

pur

pose

s

2,05

6,07

92,

056,

079

Sup

plem

enta

l Exe

cutiv

e R

etire

men

t Pla

n n

ot d

educ

tible

for t

ax re

turn

pur

pose

s

1,02

3,92

51,

023,

925

Ret

ail r

elat

ed b

ook

expe

nse

not d

educ

tible

for t

ax re

turn

pur

pose

s.

Emis

sion

Allo

wan

ce(1

8,62

7)(1

8,62

7) S

02 R

etai

l Em

issi

on A

llow

ance

ded

uctib

le fo

r tax

retu

rn p

urpo

ses.

Rat

e C

ase

Expe

nse

(961

,412

)(9

61,4

12)

Ret

ail r

elat

ed e

xpen

se d

efer

red

for b

ook

purp

oses

and

ded

ucte

d fo

r tax

pur

pose

s.

Amor

t Deb

t Dis

coun

t(7

38,5

75)

(738

,575

) B

ond

Ref

inan

cing

Deb

t Dis

coun

t boo

k ex

pens

e de

duct

ible

for t

ax p

urpo

ses

Amor

t of I

ssue

Cos

t(4

,454

,579

)(4

,454

,579

) B

ond

Ref

inan

cing

Issu

e C

ost b

ook

expe

nse

dedu

ctib

le fo

r tax

pur

pose

s

Amor

t of F

ranc

hise

Fee

49,4

3749

,437

Boo

k Am

ortiz

atio

n of

Fra

nchi

se F

ee n

ot d

educ

tible

for t

ax re

turn

pur

pose

s

Def

erre

d C

ompe

nsat

ion

582,

957

582,

957

Boo

k ex

pens

e no

t ded

uctib

le fo

r tax

retu

rn p

urpo

ses

- lab

or re

late

d to

all

func

tions

306,

833

306,

833

Fib

er O

ptic

reve

nue

that

is ta

xabl

e fo

r tax

retu

rn p

urpo

ses

and

defe

rred

for b

ook

purp

oses

.

136,

160

136,

160

Adm

in &

Con

str T

rust

to h

andl

e cl

eanu

p of

Sup

erfu

nd S

ite

3,14

13,

141

Pre

paym

ent n

ot d

educ

tible

for t

ax re

turn

pur

pose

s

Inte

rest

Exp

ense

on

FIT

Paya

ble

52,6

8852

,688

Boo

k ex

pens

e no

t ded

uctib

le fo

r tax

retu

rn p

urpo

ses

Unb

illed

Con

serv

atio

n R

even

ue23

1,61

123

1,61

1 R

etai

l rel

ated

inco

me

that

is ta

xabl

e fo

r tax

retu

rn p

urpo

ses

and

defe

rred

for b

ook

purp

oses

.

Unb

illed

Env

ironm

enta

l Rev

enue

260,

358

260,

358

Ret

ail r

elat

ed in

com

e th

at is

taxa

ble

for t

ax re

turn

pur

pose

s an

d de

ferr

ed fo

r boo

k pu

rpos

es.

FAS

109

(21,

427,

143)

(21,

427,

143)

Ass

et re

cord

ed fo

r reg

ulat

ory

purp

oses

rela

ted

to b

ook

and

tax

basi

s pl

ant a

nd n

on-p

lant

diff

eren

ces

(11,

213,

671)

(11,

213,

671)

Def

erre

d bo

ok e

xpen

se n

ot d

educ

ted

for t

ax r

etur

n pu

rpos

es re

late

d to

unr

ealiz

ed d

eriva

tives

offs

et

with

def

erre

d as

set

FAS

158-

Pens

ion

(58,

804,

686)

(58,

804,

686)

Ass

et re

cord

ed fo

r reg

ulat

ory

purp

oses

for F

AS 1

58 p

ensi

on a

nd p

ost-r

etire

men

t cos

ts

FAS

158-

SER

P(6

65,9

63)

(665

,963

) A

sset

reco

rded

for r

egul

ator

y pu

rpos

es fo

r FAS

158

pen

sion

and

pos

t-ret

irem

ent c

osts

FA

S 15

8-FA

S106

(18,

367,

932)

(18,

367,

932)

Ass

et re

cord

ed fo

r reg

ulat

ory

purp

oses

for F

AS 1

58 p

ensi

on a

nd p

ost-r

etire

men

t cos

ts

Add

add

ition

al li

nes

if ne

cess

ary.

Subt

otal

- 28

3p2

77.1

9.k

(84,

039,

260)

(61,

642,

980)

(11,

142,

606)

(25,

436,

423)

14,1

82,7

49Le

ss F

ASB

109

Abo

ve if

not

sep

arat

ely

rem

oved

(21,

427,

143)

(21,

427,

143)

0Le

ss F

ASB

106

Abo

ve if

not

sep

arat

ely

rem

oved

18,9

87,3

1118

,987

,311

Tota

l(8

1,59

9,42

8)(8

0,63

0,29

1)(1

1,14

2,60

6)(4

,009

,280

)14

,182

,749

Inst

ruct

ions

for A

ccou

nt 2

83:

2. A

DIT

item

s re

late

d on

ly to

Pro

duct

ion

are

dire

ctly

ass

igne

d to

Col

umn

D.

3. A

DIT

item

s re

late

d to

Pla

nt a

nd n

ot in

Col

umns

C &

D a

re in

clud

ed in

Col

umn

E.

4. A

DIT

item

s re

late

d to

labo

r and

not

in C

olum

ns C

& D

are

incl

uded

in C

olum

n F.

1. A

DIT

item

s re

late

d on

ly to

Non

-Ele

ctric

Ope

ratio

ns (e

.g.,

Gas

, Wat

er, S

ewer

) or T

rans

mis

sion

are

dire

ctly

ass

igne

d to

Col

umn

C.

5. D

efer

red

inco

me

taxe

s ar

ise

whe

n ite

ms

are

incl

uded

in ta

xabl

e in

com

e in

diff

eren

t per

iods

than

they

are

incl

uded

in ra

tes,

ther

efor

e if

the

item

giv

ing

rise

to th

e A

DIT

is n

ot

incl

uded

in th

e fo

rmul

a, th

e as

soci

ated

AD

IT a

mou

nt s

hall

be e

xclu

ded.

FAS

106-

Empl

oyer

s' A

ccou

ntin

g fo

r Pos

tretir

emen

t Ben

efits

O

ther

Tha

n Pe

nsio

ns

FAS

112-

Empl

oyer

s' A

ccou

ntin

g fo

r Pos

tem

ploy

men

t Ben

efits

Bond

Ref

inan

cing

- Pu

t Opt

ion

Def

erre

d Fu

el

Bond

Ref

inan

cing

- In

tere

st

Sche

dule

A-4

.1 A

ccum

ulat

ed D

efer

red

Inco

me

Taxe

s (A

DIT

) Wor

kshe

etTw

elve

Mon

ths

Ende

d D

ecem

ber 3

1, 2

009

-- Ac

tual

TAM

PA E

LEC

TRIC

CO

MPA

NY

Pens

ion

Vaca

tion

Accr

ual

6. G

ener

al P

lant

item

s w

ill be

allo

cate

d on

a la

bor r

atio

.

Bad

Deb

ts

Coa

l Con

tract

Buy

out

Def

erre

d D

eriva

tive

Bond

Ref

inan

cing

- Pr

emiu

m

Loss

from

Gra

ntor

Tru

st

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Line Description Notes Reference Year End BalancesAsset Retirement Obligations - Plant

1 Generation - Steam Company Records 469,408$ 2 Generation - Other Company Records 361,537 3 Transmission Company Records 1,868,126 4 Distribution Company Records 4,358,960 5 General Plant Company Records 42,086 6 Total (Sum Lines 1 to 5) 7,100,117$

7 Asset Retirement Obligations - Accumulated Reserve a/ Company Records 838,358$ 8 Generation - Steam (L1/L6)* L7 55,426$ 9 Generation - Other (L2/L6)* L7 42,689$

10 Transmission (L3/L6)* L7 220,582$ 11 Distribution (L4/L6)* L7 514,691$ 12 General Plant (L5/L6)* L7 4,969$ 13 Total (Sum Lines 8 to 12) 838,358$

Notes:a/ Accumulated reserve is based on a pro-rata share of plant balances.

Schedule A-4.2 Asset Retirement Obligations (ARO)Twelve Months Ended December 31, 2009 -- Actual


52


Line Description Reference Year End BalancesGenerator Step-Up Units (GSU) - Plant

1 Big Bend Steam Units Company Records 10,085,675$ 2 Big Bend Combustion Turbine Company Records 1,134,415 3 Bayside Combined Cycle Units Company Records 15,475,224 4 Bayside Combustion Turbines Company Records 3,551,030 5 Phillips Diesal Company Records 1,924,293 6 Polk IGCC Company Records 2,319,030 7 Polk Combustion Turbines Company Records 5,674,267 8 Steam Common Company Records 386,415 9 Total GSU Plant (Sum Lines 1 to 8) 40,550,349$

Generator Step Up Units (GSU) - Accumulated Reserve10 Big Bend Steam Units Company Records 4,460,377 11 Big Bend Combustion Turbine Company Records 16,260 12 Bayside Combined Cycle Units Company Records 2,746,545 13 Bayside Combustion Turbines Company Records 82,241 14 Phillips Diesal Company Records 1,004,110 15 Polk IGCC Company Records 715,466 16 Polk Combustion Turbines Company Records 875,068 17 Steam Common Company Records 173,489 18 Total GSU Accum. Reserve (Sum Lines 10 to 17) 10,073,555$

Generator Step Up Units (GSU) - Depreciation Expense19 Big Bend Steam Units Company Records 252,142 20 Big Bend Combustion Turbine Company Records 16,260 21 Bayside Combined Cycle Units Company Records 386,881 22 Bayside Combustion Turbines Company Records 82,241 23 Phillips Diesal Company Records 48,107 24 Polk IGCC Company Records 57,976 25 Polk Combustion Turbines Company Records 141,857 26 Steam Common Company Records 9,660 27 Total GSU Depreciation Expense (Sum Lines 19 to 26) 995,123$

Generator Step Up Units (GSU) - O&M Expense28 Transmission Plant FM-1,p207.58.g 531,714,712$ 29 Transmission GSU Facilities L9 40,550,349 30 GSU Facilities Ratio to Transmission Plant L29/L28 7.63%31 Transmission O&M Expense FM-1,p321.112.g 14,341,817 32 Less Load Dispatch Accts 561, subpnt 1,2,3, & 4 FM-1,p321.85.b to 321.88.b 1,370,663 33 Less Transm. by Others, Acct 565 FM-1, p321.96.b 315,052 34 Revised Transmission O&M Expense L31 - L32 - L33 12,656,102 35 Total GSU O&M Expense L34 * L30 965,197$


Schedule A-4.3 Generator Step-Up Units (GSU)Twelve Months Ended December 31, 2009 -- Actual

53


A-4.4

Line Description Reference Capital Additions1 January Company Records 16,354,519 2 February Company Records 5,473,594 3 March Company Records 4,100,346 4 April Company Records 13,306,457 5 May Company Records 125,282,477 6 June Company Records 11,855,210 7 July Company Records 5,625,037 8 August Company Records 1,830,141 9 September Company Records 1,384,905 10 October Company Records 2,867,446 11 November Company Records 1,621,357 12 December Company Records 28,351,472 13 Total Production Capital Additions (Sum Lines 1 to 12) 218,052,961


Schedule A-4.4 Capital Additions Placed in ServiceTwelve Months Ended December 31, 2010 -- Projected

54



Production Total

Company Production

Total Demand EnergyNon-fuel

EnergyFuel

Line Description Notes Reference (1) (2) (3) (4) (5)

1 555 Purchased Power Expense a/ FM-1, p327.m 177,674,303 177,674,303 92,148,674 4,114,884 81,410,745

2 556 System Control and Load Dispatching FM-1, p321.77.b 891,081 891,081 891,081

3 557 Other Expenses FM-1, p321.78.b - - -

4 Other Production O&M Expenses A-5.1, L56 Sum

(Cols. 1 + 2) 144,848,908 144,848,908 83,003,316 61,845,592

5 Total Production excluding Fuel Used in Generation (Sum Lines 1 to 4) 323,414,292 323,414,292 176,043,071 65,960,476 81,410,745

6 A&G Expenses A-6, L12 112,517,264 59,399,823 36,888,861 22,510,962 -

7 Subtotal O&M Expense L5 + L6 435,931,556 382,814,115 212,931,932 88,471,438 81,410,745

8 501 Fuel Expense FM-1, p320.5.b 274,716,159 274,716,159 274,716,159

9 518 Fuel Expense FM-1, p320.25.b - - -

10 547 Fuel Expense FM-1, p321.63.b 564,396,140 564,396,140 564,396,140

11 Less Gains on Disposition of Allowance FM-1, p114.22.c 92,691 92,691 92,691

12 Total Fuel Expense (Sum Lines 8 to 11) - L11 839,112,299 839,112,299 - - 839,112,299

13 Total Production O&M Expense L7 + L12 1,275,043,855 1,221,926,414 212,931,932 88,471,438 920,523,044

FERC Form No. 1, p 326&327, Purchased Power Expense Total Demand

Other:Classified as Demand a/

Classified as

Non-Fuel Energy a/ Energy

Line Description Reference (a) (b) (c) (d) (e)14 Florida Power Corporation Invoices 24,657,357 16,200,000 8,457,35715 Florida Power Corporation Invoices 5,574,067 0 5,574,067 016 Florida Power & Light Invoices 2,632,716 0 2,632,71617 Florida Power & Light Invoices 105,870 0 105,870 018 Calpine Invoices 17,912,849 7,058,400 916,667 9,937,78219 Cargill Alliant Invoices 2,420,398 0 2,420,39820 Constellation Commodities Invoices 419,862 0 419,86221 Cobb Electric Membership Corporation Invoices 382,014 0 382,01422 JP Morgan Venture Invoices 3,437,752 0 3,437,75223 DeSoto County Invoices 300,856 0 300,85624 Okeelanta Corporation Invoices 234,935 0 234,93525 Orlando Utilities Commission Invoices 1,197,514 0 1,197,51426 Pasco Cogen Invoices 22,209,653 8,450,640 13,759,01327 Rainbow Energy Marketers Invoices 6,150 0 6,15028 Reedy Creek Improvement District Invoices 33,150 0 33,15029 Reliant Energy Invoices 13,645,539 7,925,280 5,870 5,714,38930 Seminole Electric Cooperative, Inc. Invoices 622,503 0 622,50331 Seminole Electric Cooperative, Inc. Invoices 30,267 0 30,267 032 Southern Company Invoices 928,724 0 928,72433 City of Tallahassee Invoices 59,315 0 59,31534 City of Tallahassee Invoices 24,897 0 24,897 035 The Energy Authority Invoices 1,815,553 0 1,815,55336 The Energy Authority Invoices 42,555 0 42,555 037 Cobb Electric Membership Corporation Invoices 16,650 0 16,65038 Constellation Commodities Invoices 2,210 0 2,21039 JP Morgan Venture Invoices 14,388 0 14,38840 Hardee Power Partners, Ltd. Invoices 31,693,448 20,466,098 3,198,217 8,029,13341 City of Tampa Invoices 7,653,802 3,423,660 4,230,14242 Hillsborough County Invoices 18,563,132 12,377,910 6,185,22243 IMC-Agrico-New Wales Invoices 2,903,954 0 2,903,95444 CF Industries, Inc. Invoices 188,688 0 188,68845 IMC-Agrico-South Pierce Invoices 1,350,156 0 1,350,15646 Auburndale Power Partners, L.P. Invoices 382,985 0 382,98547 Orange Cogeneration Invoices 12,539,649 10,463,160 2,076,48948 Cutrale Citrus Juices US Invoices 25 0 2549 Cargill Fertilizer Millpoint Invoices 1,596,514 0 1,596,51450 Cargill Ridgewood Invoices 1,673,747 0 1,673,74751 Net Imbalance Invoices 400,459 0 400,45952 TOTAL Sum Lines (14 to 51) 177,674,303 86,365,148 5,783,526 4,114,884 81,410,745

a/ 555 Purchased Power (FERC Form No. 1, p 327). The "Other" component is classified to demand or non-fuel energy dependent on source.

Schedule A-5 Production Operations & Maintenance (O&M) ExpensesTwelve Months Ended December 31, 2009 -- Actual

55


Wages & Salaries fromCompany Records

Demand Energy Demand EnergyLine Description Notes Reference (1) (2) /c (3) (4)

1 500 Operation Supervision and Engineering 3,712,740 948,871 2 501 Fuel n/a - 3 502 Steam Expenses 17,967,242 5,702,052 4 503 Steam from Other Sources. - 5 504 Steam Transferred—Credit - 6 505 Electric Expenses 2,709,292 2,493,886 7 506 Miscellaneous Steam Power Expenses 7,847,430 2,460,324 8 507 Rents - 9 509 Allowances (3,133) 10 510 Maintenance Supervision and Engineering 369,067 349,747 11 511 Maintenance of Structures 5,698,436 1,794,314 12 512 Maintenance of Boiler Plant 39,869,282 10,624,547 13 513 Maintenance of Electric Plant 9,679,080 2,242,487 14 514 Maintenance of Miscellaneous Steam Plant 2,769,515 524,809 15 517 Operation Supervision and Engineering16 518 Fuel n/a17 519 Coolants and Water18 520 Steam Expenses19 521 Steam From Other Sources20 522 Steam Transferred—Credit21 523 Electric Expenses22 524 Miscellaneous Nuclear Power Expenses23 525 Rents 24 528 Maintenance Supervision and Engineering25 529 Maintenance of Structures26 530 Maintenance of Reactor Plant Equipment27 531 Maintenance of Electric Plant28 532 Maintenance of Miscellaneous Nuclear Plant29 535 Operation Supervision and Engineering30 536 Water for Power31 537 Hydraulic Expenses32 538 Electric Expenses33 539 Miscellaneous Hydraulic Power Generation Expenses34 540 Rents35 541 Maintenance Supervision and Engineering36 542 Maintenance of Structures37 543 Maintenance of Reservoirs, Dams and Waterways38 544 Maintenance of Electric Plant39 545 Maintenance of Miscellaneous Hydraulic Plant40 546 Operation Supervision and Engineering 3,891,537 1,677,068 41 547 Fuel n/a - 42 548 Generation Expenses 11,803,837 6,105,856 43 549 Miscellaneous Other Power Generation Expenses 13,614,743 2,082,881 44 550 Rents - 45 551 Maintenance Supervision and Engineering 936,216 889,683 46 552 Maintenance of Structures 10,490,063 1,354,487 47 553 Maintenance of Generating and Electric Plant 11,931,296 2,726,976 48 554 Maintenance of Miscellaneous Other Power Generation Plant 597,068 92,910 49 555 Purchased Power n/a n/a50 556 System Control and Load Dispatching n/a n/a51 557 Other Expenses n/a - 52 Additional O&M Items:53 Plus GSU O&M Expense a/ A-4.3, L35 965,197 54 Less Storm Expenses from Prior Year b/ - 55 Plus Storm Expenses from Current Year b/ - 56 Total Demand and Total Energy Expense (Sum Lines 1 to 55) 83,003,316 61,845,592 26,127,139 15,943,757

57 Calculation of Production W&S Allocator Prorate Demand/Sum Demand & Energy 62.10% 37.90%

Notes:a/ GSU O&M is calculated on an equivalent pro-rata of GSU Plant to Transmission Plant. It is removed from Transmission O&M

and input as part of Production O&M.b/ Major Storm expense will be added when incurred. Formula excludes the storm accrual activity.c/ Fuel and purchased power are excluded on this schedule. See Schedule for A-5 for fuel and purchased power amounts.

Production O&MFM-1,320-321,L1-80, col b


Schedule A-5.1 Classification of Fixed and Variable Production ExpensesTwelve Months Ended December 31, 2009 -- Actual

56


System Allocator Production Demand Energy Line Description Notes Reference (1) (2) (3) (4) (5)

1 Total Administrative & General Expense FM-1 p323.197.b 126,112,516 2 Less: Accrual Post-retirement Benefits Other than Pensions (PBOPs) Company Records 12,209,421 3 Plus: PBOP Actual Claim Expense FERC Authorized 9,154,918 4 Less: Property Insurance Expense FM-1 p323.185.b 14,387,622 5 Less: Regulatory Commission Expense FM-1 p323.189.b 3,622,399 6 Less: General Advertising Expense Account 930.1 FM-1 p323.191.b 251,683 7 Less: EPRI Dues Company Records - 8 Subtotal -- Allocated on General Plant W&S Allocator L1 + L3 - L2 - (Sum Lines 4 to 7) 104,796,309 0.5209 54,591,427 33,902,720 20,688,707

9 Plus: Property Insurance Expense L4 14,387,622 10 Less: Storm Reserve Accrual b/ Company Records 6,666,667

11 Plus Property Insurance - Allocated on Gross Plant a/, c/ L9 - L10 7,720,955 0.6228 4,808,396 2,986,141 1,822,255 12 Total Administrative & General Expense L8 + L11 112,517,264 59,399,823 36,888,861 22,510,962

13 Production Payroll FM-1, p354.20.b 42,840,774 14 A&G Payroll FM-1, p354.27.b 41,069,751 15 Total Payroll FM-1, p354.28.b 123,308,946 16 Payroll (excl. A&G) L15 - L14 82,239,195 17 General Plant W&S Allocator L13 / L16 52.09%

Notes:a/ Functionalized on Production Gross Plant Allocator, Schedule A-4, L8.b/ Removes Storm Reserve Accruals in A&G.c/

General Plant Wages & Salaries (W&S) Allocator:

Total Property Insurance net of storm accrual is allocated to production demand and energy based on the Production W&S Allocator.

Schedule A-6 Production-Related Administrative & General Expense Allocation and W&S Allocator


Twelve Months Ended December 31, 2009 -- Actual

57


FERC Form No. 1, p350, a/ Total Utility DirectlyLine Description Expense YTD Production Other Assigned

(1) (2) (3) (4) (5) (6)1 Florida Public Service Comm. (FPSC)23 FPSC-090001-Fuel and Purchased Power Cost 82,253 82,253 4 Recovery Clause with GPIF56 FPSC-090002-EG-Energy Conservation Cost 173,169 173,169 78 FPSC-090007-EI-Environmnetal Cost Recovery 9,109 9,109 9 Clause1011 Rate Case - Docket No. - 080317 - EI 1,444,407 1,444,407 1213 Extension of Small Power Production 13,819 13,819 14 Agreement, Docket No. - 090146-EQ1516 Solar Energy Power Purchase Agreement with 16,704 16,704 17 Energy 5.0, LLC Docket No. - 090109-EI1819 FPSC General - 1,096,083 1,096,083 2021 Federal Energy Regulatory Comm. (FERC)2223 North American Electric Reliability Corp.24 Critical Infrastructure Protection 82,127 82,127 25 Reliability 27,611 27,611 2627 Electric Quarterly Report 10,210 10,210 2829 Market Based Rates/Southeast Simultaneous 17,211 17,211 30 Import Limitation Study3132 O.A.T.T. 8,525 8,525 3334 Standards of Conduct 12,554 12,554 3536 Interchange Rates for Schedules A&B 7,991 7,991 3738 Qualifying Facilities Transmission Service 1,111 1,111 39 Rates4041 FERC General 612,324 306,162 306,162 4243 Federal Communications Comm. (FCC)44 FCC Pole Attachment NPRM 7,191 7,191 4546 Total Regulatory Commission Expense 3,622,399 446,248 3,176,151 -

47 Total 12 Months System Firm Peaks Sum FM-1, p401b.d 40,952,00048 Requirements Customers Sum Firm Peak Demands Company Records 1,295,035 49 Direct Assignment of Regulatory Commission Expenses ($/kW) Line 46/Firm Peak 0.01$ -$ 50 Total Direct Assignment ($/kW) Sum L49 (Cols. 4&6) 0.01$

Notes:a/ Regulatory commission expenses vary from year to year. Line references are subject to change as FERC Form No. 1, p 350 is a free-form page.


Schedule A-6.1 Regulatory Commission ExpensesTwelve Months Ended December 31, 2009 -- Actual

58



Total Demand Energy Line Description Notes Reference (1) (2) (3)

1 Steam Production FM-1 p336.2.f 38,438,383 38,438,383 2 Nuclear Production FM-1 p336.3.f - 3 Hydraulic Production (Convention & Pumped) FM-1 p336.4.f + 5.f - 4 Other Production FM-1 p336.6.f 64,062,412 64,062,412 5 Generator Step-Up Units A-4.3, L27, Col 1 995,123 995,123 6 Sebring Acquisition Adjustment b/ Company Records (423,408) (423,408) 7 Subtotal (Sum Lines 1 to 6) 103,072,510 103,072,510 - 8 Production-Related G&I Plant a/ 8,944,285 9 Production W&S Allocator A-5.1, L57 0.6210 0.3790

10 Allocation to Production Demand & Energy L8 * L9 5,554,637 3,389,647 11 Total Production Amortization & Depreciation Expense L7 + L8 + L10 112,016,795 108,627,148 3,389,648

Notes:a/ General & Intangible Amortization & Depreciation FM-1 p336.1.f + .10.f 17,169,876

General Plant W&S Allocator A-6, L17, Col 1 0.5209 Production portion of G&I Amortization & Depreciation 8,944,285

b/ Sebring Acquisition Adjustment. The associated purchase discount is being amortized annually as a credit to depreciation expense.c/ Current rates approved by FPSC, 2008, FPSC Order PSC-08-0014-PAA-EI, January 4, 2008. Rates can only be changed

through a FPA Section 205 or 206 rate filing at FERC.

Applied Depreciation Rates FM-1 p337.e c/ FERC Account Number & Description Applied % RatesSteam Production310 310.01 Land & Land Rights-Misc 0.0

310.11 Land & LR-Dinner Lake 0.0310.40 Land & Land Rights-BBCM 0.0310.50 Land & Land Rights-GNCM 0.0310.70 Land & LR-Gannon Trust 0.0

311 311.01 Str & Improvements-Misc 3.5311.30 Str & Improvements-BPC 2.3311.31 Str & Improvements-BP1 2.3311.32 Str & Improvements-BP2 2.3311.40 Str & Improvements-BBCM 2.0311.41 Str & Improvements-BB1 1.4311.42 Str & Improvements-BB2 1.6311.43 Str & Improvements-BB3 1.2311.44 Str & Improve-BB4 MAIN STT 1.4311.45 Str & Improvements-BB 4 FGD 1.5311.46 Str & Improve-BB1 & 2 FGD 2.6311.75 Str & Improvements-BPC 2.3

312 312.30 Boiler Plant Eq-BPC 2.5312.31 Boiler Plant Eq-BP1 2.9312.32 Boiler Plant Eq-BP2 2.9312.40 Boiler Plant Eq-BBCM 2.6312.41 Boiler Plant Eq-BB1 3.3312.42 Boiler Plant Eq-BB2 3.1312.43 Boiler Plant Eq-BB3 2.6312.44 Boiler Plant Eq-BB4 MAIN STT 2.4312.45 Boiler Plant Eq-BB4 FGD 2.3312.46 Boiler Plant Eq-BB1&2 FGD 2.9312.75 Boiler Plant Eq-BPC 2.5

314 314.30 Turbogenerator Units-BPC 2.9314.31 Turbogenerator Units-BP1 4.0314.32 Turbogenerator Units-BP2 3.9314.40 Turbogenerator Units-BBCM 1.8314.41 Turbogenerator Units-BB1 2.5314.42 Turbogenerator Units-BB2 2.5314.43 Turbogenerator Units-BB3 1.8314.44 Turbogen Units-BB4 MAIN STT 2.0

315 315.30 Accessory Electric Eq-BPC 4.3315.31 Accessory Electric Eq-BP1 3.2315.32 Accessory Electric Eq-BP2 3.1315.40 Accessory Electric Eq-BBCM 3.0315.41 Accessory Electric Eq-BB1 2.5315.42 Accessory Electric Eq-BB2 2.5

Production

Schedule A-7 Production-Related Depreciation Expense and Applied Depreciation RatesTwelve Months Ended December 31, 2009 -- Actual

59



Applied Depreciation Rates FM-1 p337.e c/ FERC Account Number & Description Applied % Rates

315.43 Accessory Electric Eq-BB3 2.5315.44 Access Elect Eq-BB4 MAIN STT 2.1315.45 Accessory Elect Eq-BB4 FGD 2.1315.46 Accessory Elect Eq-BB1&2 FGD 3.3

316 316.01 Misc Power Plant Equip 3.5316.17 Tools Misc Supply 7yr 14.3316.30 Misc Power Plant Eq-BPC 3.4316.31 Misc Power Plant Eq-BP1 2.5316.32 Misc Power Plant Eq-BP2 2.6316.40 Misc Power Plant Eq-BBCM 3.1316.41 Misc Power Plant Eq-BB1 1.2316.42 Misc Power Plant Eq-BB2 2.0316.43 Misc Power Plant Eq-BB3 2.7316.44 Misc Pwr Plt Eq-BB 4 MAIN ST 1.7316.45 Misc Power Plant Eq-BB 4 FGD 2.0316.46 Misc Power Plt Eq-BB1&2 FGD 2.5316.47 Tools Big Bend 7yr 14.3

Other Production340 340.28 Land & Land Rights-Phillips 0.0

340.30 Land & Land Rights-BPC 0.0340.42 Land & Land Rights-BBCT1&3 0.0340.81 Land & Land Rights-Polk U1 0.0

341 341.28 Str and Improve-Phillips 3.4341.30 Str and Improvements-BPC 2.3341.31 Str and Improvements-BP1 2.3341.32 Str and Improvements-BP2 2.3341.33 Str and Improvements-BP3 4.3341.34 Str and Improvements-BP4 4.3341.35 Str and Improvements-BP5 4.3341.36 Str and Improvements-BP6 4.3341.44 Str and Improvements-BBCT4 4.3341.80 Str and Improve-Polk Comm 2.3341.81 Str and Improvements-Polk U1 2.5341.82 Str and Improvements-Polk U2 2.7341.83 Str and Improvements-Polk U3 2.6341.84 Str and Improvements-Polk U4 4.3341.85 Str and Improvements-Polk U5 4.3

342 342.28 FuelHolders,ProdAcc-Phillips 3.0342.30 Fuel Holders,Prod Acc-BPC 2.5342.31 Fuel Holders,Prod Acc-BP1 2.9342.32 Fuel Holders,Prod Acc-BP2 2.9342.33 Fuel Holders,Prod Acc-BP3 4.3342.34 Fuel Holders,Prod Acc-BP4 4.3342.35 Fuel Holders,Prod Acc-BP5 4.3342.36 Fuel Holders,Prod Acc-BP6 4.3342.44 Fuel Holders,Prod Acc-BBCT4 4.3342.80 Fuel Holders,Prod Acc-Polk C 2.2342.81 Fuel Holders,Prod Acc-Polk 1 3.4342.82 Fuel Holders,Prod Acc-Polk 2 2.9342.83 Fuel Holders,Prod Acc-Polk 3 2.9342.84 Fuel Holders,Prod Acc-Polk 4 4.3342.85 Fuel Holders,Prod Acc-Polk 5 4.3

343 343.28 Prime Movers-Phillips 3.7343.30 Prime Movers-BPC 2.9343.31 Prime Movers-BP1 4.0343.32 Prime Movers-BP2 3.9343.33 Prime Movers-BP3 4.3343.34 Prime Movers-BP4 4.3343.35 Prime Movers-BP5 4.3343.36 Prime Movers-BP6 4.3343.44 Prime Movers-BBCT4 4.3343.80 Prime Movers-Polk Common 2.0343.81 Prime Movers-Polk U1 6.4343.82 Prime Movers-Polk U2 7.6343.83 Prime Movers-Polk U3 6.2343.84 Prime Movers-Polk U4 4.3343.85 Prime Movers-Polk U5 4.3343.90 Prime Movers-Tampa Biosolids 4.5


60



Applied Depreciation Rates FM-1 p337.e c/ FERC Account Number & Description Applied % Rates

345 345.28 Accessory Elect Eq-Phillips 3.5345.30 Accessory Electric Eq-BPC 4.3345.31 Accessory Electric Eq-BP1 3.2345.32 Accessory Electric Eq-BP2 3.1345.33 Accessory Electric Eq-BP3 4.3345.34 Accessory Electric Eq-BP4 4.3345.35 Accessory Electric Eq-BP5 4.3345.36 Accessory Electric Eq-BP6 4.3345.44 Accessory Electric Eq-BBCT4 4.3345.80 Accessory Elect Eq-Polk Comm 2.4345.81 Accessory Elect Eq-Polk U1 3.1345.82 Accessory Elect Eq-Polk U2 2.9345.83 Accessory Elect Eq-Polk U3 3.0345.84 Accessory Elect Eq-Polk U4 4.3345.85 Accessory Elect Eq-Polk U5 4.3

346 346.28 Misc Power Plant Eq-Phillips 4.2346.30 Misc Power Plant Eq-BPC 3.4346.31 Misc Power Plant Eq-BP1 2.5346.32 Misc Power Plant Eq-BP2 2.6346.33 Misc Power Plant Eq-BP3 4.3346.34 Misc Power Plant Eq-BP4 4.3346.35 Misc Power Plant Eq-BP5 4.3346.36 Misc Power Plant Eq-BP6 4.3346.44 Misc Power Plant Eq-BBCT4 4.3346.80 Misc Power Plt Eq-Polk Comm 2.2346.81 Misc Power Plant Eq-Polk U1 3.4346.82 Misc Power Plant Eq-Polk U2 2.8346.83 Misc Power Plant Eq-Polk U3 2.9346.84 Misc Power Plant Eq-Polk U4 4.3346.85 Misc Power Plant Eq-Polk U5 4.3346.87 Tools Polk 7yr 14.3

General Plant389 389.00 Land & Land Rights 0.0390 390.00 Structures & Improvements 3.5391 391.01 Office Fur, Fixt & Equip 7yr 14.3

391.02 Computer & Perph Equip 4yr 25.0391.03 Data Handling Equip 7yr 14.3391.04 Computer Hardw-Mainframe 5yr 20.0

392 392.01 Trans Equipment - Auto 12.6392.02 ED Trans Equip - L Truck 12.6392.03 ED Trans Equip - H Truck 5.9392.04 ED Trans Equip - M Truck 7.8392.12 ES Trans Equip - L Truck 8.5392.13 ES Trans Equip - H Truck 5.9392.14 ES Trans Equip - M Truck 5.7

393 393.00 Stores Equipment 7yr 14.3394 394.00 Tool Shop & Garage Equip 7yr 14.3

394.03 Tool Vehicles 7yr 14.3395 395.00 Laboratory Equipment 7yr 14.3396 396.00 Power Operated Equipment 7yr 14.3397 397.00 Communication Equipment 7yr 14.3

397.25 Fiber Optic 6.9398 398.00 Miscellaneous Equipment 7yr 14.3

Intangibles303 303.00 Misc Intangible Plant 5yr 20.0


61


Line Description Notes Reference c/ System

(1) Allocator

(2) Production

(3)

Labor Related1 Unemployment FM -1, p263.6.i + .23.i 209,994 2 FICA FM -1, p263.9.i 11,093,087 3 Total Labor Related L1 + L 2 11,303,081 4 General Plant W&S Allocator a/ A-6, L17 52.09%5 Total Production Labor Related L3 * L4 5,888,102

Plant Related6 Real and Personal Property FM-1, p263.32.i 41,438,840 7 Gross Plant Allocator b/ A-4, L7, Col 2 62.28%8 Total Production Plant Related L6 * L7 25,806,959

Other Included7 Intangible FM-1, p263.26.i 2,626 8 Occupational License FM-1, p263.28.i 57,350 9 Excise Tax FM-1, p263.11.i 1,185 10 Sales Tax FM-1, p263.29.i 188,487 11 Total Other (Sum Lines 7 to 10) 249,648 12 Gross Plant Allocator b/ 62.28%13 Total Production Other 155,474

Other Excluded14 Gross Receipts FM-1, p263.20.i 52,640,375 15 Franchise Fees FM-1, p263.35.i 39,429,556 16 Public Serv Comm. FM-1, p263.25.i 1,522,000 17 Prior Period FICA FM-1, p263.10.i (508,111) 18 Other TOI Excluded (Sum Lines 14 to 17) 93,083,818

19 Total Production Taxes Other than Income L5 + L8 + L13 31,850,535

20 Total Taxes Other than Income L3 + L6 + L11+ L18 146,075,387 21 Difference (rounding) L22 - L20 (0) 22 Total Taxes Other than Income FM-1, p114.14.c 146,075,387

Notes:a/ General Plant W&S Allocator, A-6, L17, Col 1b/ Production Gross Plant Allocator, A-4, L7, Col 2c/ Line references are subject to change as FERC Form No. 1, p 263 is a free-form page.

Schedule A-8 Production-Related Taxes Other than Income Taxes (TOI)



62


Amount Share Cost Wtd CostLine Description Notes Reference (1) (2) (3) (4)

1 Long-Term Debt FM-1, p112.18.c - 19.c + 21.c 1,768,835,000 49.08% 6.39% 3.14%2 Preferred Stock FM-1, p112.3.c - - 0.00%3 Common Equity a/ FM-1, p112.16 - Line 2 1,835,503,849 50.92% 11.25% 5.73%4 Total (ROR rounded to four decimals) 3,604,338,849 100.00% 8.87%

5 Proprietary Capital FM-1, p112.16.c 1,831,712,084 6 Less: Preferred Stock FM-1, p112.3.c - 7 Less: Acct. 216.1 FM-1, p112.12.c 263,668 8 Less: Accum. Other Comp. Income Acct 219 FM-1, p112.15.c (4,055,433) 9 Common Equity L5 - L6 - L7 - L8 1,835,503,849

Long-Term Interest10 Interest on Long-Term Debt (427) FM-1, p117.62.c 106,724,902 11 Amort. of Debt Disc. and Expense (428) FM-1, p117.63.c 3,899,345 12 Amortization of Loss on Reaquired Debt (428.1) FM-1, p117.64.c 2,722,757 13 Amort. of Premium on Debt-Credit (429) FM-1, p117.65.c (257,344) 14 Total Interest (Sum Lines 10 to 13) 113,089,660 15 Cost of Long-Term Debt L14 / L1 6.39%

Preferred Cost Rate16 Preferred Dividends FM-1, p118.29.c - 17 Preferred Cost Rate L16 / L2 -

Notes:a/ The Cost of Capital used to determine the rate of return on rate base will be calculated using a Return on Equity

(ROE) that is fixed and can only be changed through a FPA Section 205 or 206 rate filing at FERC.

Total Company

Schedule A-9 Composite Cost of Capital



63



Production

Line Description Reference Total

(1) Demand

(2) Energy

(3) 1 Total Rate Base A-3, L16 2,761,960,653 2,638,501,096 117,685,132 2 Weighted Return on Long-Term Debt + Equity A-9, L4, Col 4 8.87% 8.87% 8.87%3 Return on Rate Base L1 * L2 244,985,910 234,035,047 10,438,671 4 Combined Income Tax Factor L 15 0.4059 0.4059 0.40595 Subtotal Income Tax L3 * L4 99,439,781 94,994,826 4,237,057 6 ITC Adjustment (-1) *L 13 (further allocated to D & E by RB on L1) (373,275) (356,590) (16,685) 7 Total Income Tax L5 + L6 99,066,506 94,638,236 4,220,371

8 Amortized Investment Tax Credit (ITC): 9 1/(1 - T) L16 1.6281

10 Amortized Investment Tax Credit FM-1, p266.8.f 368,137 11 ITC Adjustment L9 * L10 599,376 12 Production Gross Plant Allocator A-4, L7, Col 2 62.28%13 ITC Production Adjustment L11 * L12 373,275

14 T=1 - {[(1 - SIT) * (1 - FIT)] / (1 - SIT * FIT * p)} = 38.58%15 CIT=(T/1-T) * (1-(WCLTD/R)) = 40.59%

where WCLTD=(A-9, L1, Col 4) and where R= (A-9, L4, Col 4) and where FIT, SIT & P are as below.16 1 / (1 - T) where T = L14 1.628

17 where FIT rate = FIT = Federal Income Tax 0.350018 where SIT rate = SIT = State Income Tax 0.055019 where p = (percentage of Federal Income Tax deductible for state purposes) 0.0020 where WCLTD = (A-9, L1, Col. 4 - Weighted Cost Long-Term Debt) 3.14%21 where R = (A-9, L4, Col. 4 - Total Weighted Cost Long-Term Debt + Equity) 8.87%

Schedule A-10 Production-Related Income TaxTwelve Months Ended December 31, 2009 -- Actual

64


Calculation of True-Up Amounts

Line Description Amount1 A-1 (of Prior Year Formula), L13

2 A-1, L13 -

3 Difference L2 - L1 -

4 A-2 (of Prior Year Formula), L9

5 A-2, L9 -


7 A-2 (of Prior Year Formula), L14

8 A-2, L14 -


Calculation of Interest on Over/Under Collections from Prior Year

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l)Production Fixed Cost Difference Fuel and Purchased Power Cost Difference Non-Fuel Variable Cost Difference

FERC Interest Rate for March of Current Year

Months

1/12 of Amount on Line 3

Interest = (b) * (c) * (d)

Total including Interest (d) + (e)


Interest = (b) * (c) * (g)

Total including Interest (g) + (h)


Interest = (b) * (c) * (j)

Total including Interest (j) + (k)

10 Aug 11.5 - - - - - - - - - 11 Sept 10.5 - - - - - - - - - 12 Oct 9.5 - - - - - - - - - 13 Nov 8.5 - - - - - - - - - 14 Dec 7.5 - - - - - - - - - 15 Jan 6.5 - - - - - - - - - 16 Feb 5.5 - - - - - - - - - 17 Mar 4.5 - - - - - - - - - 18 Apr 3.5 - - - - - - - - - 19 May 2.5 - - - - - - - - - 20 Jun 1.5 - - - - - - - - - 21 Jul 0.5 - - - - - - - - - 22 Total - - -

Note: In column b, enter zero for any month the rate was not in effect; pro-rate for any partial month.Amortization over

Rate Year @ Interest Rate Above

Amortization over Rate Year @

Interest Rate Above

Amortization over Rate Year @

Interest Rate Above23 Aug - - - 24 Sept - - - 25 Oct - - - 26 Nov - - - 27 Dec - - - 28 Jan - - - 29 Feb - - - 30 Mar - - - 31 Apr - - - 32 May - - - 33 Jun - - - 34 Jul - - - 35 Total with interest Enter A-1 Line 20 > - Include in A-2 Line 22 > - Include in A-2 Line 22 > -


Schedule A-11 Reconciliation Worksheet Calculation of True-Up Including Interest

Current Year Formula(Populated with Prior Year FM-1 Data)

Prior Year Annual Production Demand Cost Excluding Over/(Under) Collection and Interest


Reference

Prior Year Annual Non-Fuel Energy Charge Excluding Over/(Under) Collection and Interest


Prior Year Annual Production Fuel and Purchased Power Cost Excluding Over/(Under) Collection and Interest

65


2009

Act

ual D

ata

Line

Des

crip

tion

Not

esR

efer

ence

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Tota

l

Flor

ida

Pow

er C

orpo

ratio

n d/

b/a

Prog

ress

Ene

rgy

Flor

ida

1N

et E

nerg

y fo

r Loa

d (M

Wh)

:PR

Sch

7,98

09,

380

3,29

05,

810

11,9

7010

,920

8,12

08,

960

1,96

07,

700

1,61

01,

890

79,5

902

Billi

ng D

eman

d (M

W)

PR S

ch70

7070

7070

7070

7070

7070

703

Cur

rent

Cus

tom

er C

harg

e ($

/Mon

th)

Tarif

f36

7$

367

$

367

$

367

$

367

$

367

$

367

$

367

$

367

$

367

$

367

$

36

7$

4,

404

$

4

Cur

rent

Non

-Fue

l Ene

rgy

Cha

rge

($/k

Wh)

Tarif

f0.

0055

40.

0055

40.

0055

40.

0055

40.

0055

40.

0055

40.

0055

40.

0055

40.

0055

40.

0055

40.

0055

40.

0055

45

a/Ta

riff

0.05

863

0.05

863

0.05

863

0.05

863

0.04

941

0.04

941

0.04

941

0.04

941

0.04

941

0.04

941

0.04

941

0.04

941

6C

urre

nt D

eman

d C

harg

e in

cl. T

rans

mis

sion

($/k

W)

c/Ta

riff

9.42

$

9.

42$

9.

42$

9.

42$

9.

42$

9.

42$

9.

42$

9.

42$

9.

42$

9.

42$

9.

42$

9.42

$

7Pr

ior P

erio

d Fu

el A

djus

tmen

t Tru

e-up

Cha

rge

Tarif

f11

7,38

1$

117,

427

$

117,

241

$

117,

040

$

116,

897

$

116,

848

$

116,

816

$

116,

764

$

116,

725

$

116,

695

$

116,

674

$

11

6,65

2$

1,

403,

160

$

8Pr

opos

ed C

usto

mer

Cha

rge

($/M

onth

)A-

1.L1

950

0$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

50

0$

9

Prop

osed

Non

-Fue

l Ene

rgy

Cha

rge

(NFV

C) (

$/kW

h)A-

2.L1

90.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

210

b/A-

2.L2

00.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

511

Prop

osed

Dem

and

Cha

rge

(GC

C) (

$/kW

)A-

1.L1

816

.91

$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

12c/

OAT

T Sc

h 7

1.07

$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.07

$

13c/

OAT

T Sc

h 1

0.03

7$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

14To

tal C

ost a

t Cur

rent

Rat

es1,

289,

225

$

1,37

9,10

9$

988,

127

$

1,14

9,63

5$

1,45

7,00

5$

1,37

6,66

9$

1,22

2,77

7$

1,26

8,88

3$

884,

194

$

1,19

9,57

7$

864,

911

$

88

0,27

5$

13

,960

,385

$

15C

urre

nt R

ate

Cal

cula

tion:

(3) +

[ (1

) * (4

+ 5

) + (2

) * (6

) ] *

1,0

00 +

(7)

16To

tal C

ost a

t Pro

pose

d R

ates

1,67

3,35

8$

1,

745,

546

$

1,

431,

527

$

1,

561,

466

$

1,

879,

095

$

1,

824,

954

$

1,

680,

577

$

1,

723,

890

$

1,

362,

948

$

1,

658,

920

$

1,

344,

901

$

1,35

9,33

8$

19,2

46,5

21$

17

Prop

osed

Rat

e C

alcu

latio

n: (8

) + [

(1) *

(9 +

10)

+ (2

) * (1

1 +

12 +

13)

] *

1,00

018

Diff

eren

ceL1

6 - L

1438

4,13

3$

366,

438

$

443,

400

$

411,

831

$

422,

091

$

448,

285

$

457,

800

$

455,

007

$

478,

754

$

459,

343

$

479,

990

$

47

9,06

4$

5,

286,

136

$

City

Of S

t. C

loud

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Tota

l1

Net

Ene

rgy

for L

oad

(MW

h):

PR S

ch97

564

51,

080

2,13

01,

815

1,86

02,

010

1,47

01,

905

3,28

51,

980

2,07

021

,225

2Bi

lling

Dem

and

(MW

)PR

Sch

1515

1515

1515

1515

1515

1515

3C

urre

nt C

usto

mer

Cha

rge

($/M

onth

)Ta

riff

367

$

36

7$

36

7$

36

7$

36

7$

36

7$

36

7$

36

7$

36

7$

36

7$

36

7$

367

$

4,40

4$

4C

urre

nt N

on-F

uel E

nerg

y C

harg

e ($

/kW

h)Ta

riff

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

5a/

Tarif

f0.

0586

30.

0586

30.

0586

30.

0586

30.

0494

10.

0494

10.

0494

10.

0494

10.

0494

10.

0494

10.

0494

10.

0494

16

Cur

rent

Dem

and

Cha

rge

incl

. Tra

nsm

issi

on ($

/kW

)c/

Tarif

f9.

42$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.

42$

7

Prio

r Per

iod

Fuel

Adj

ustm

ent T

rue-

up C

harg

eTa

riff

29,5

87$

29,5

99$

29

,552

$

29,5

01$

29

,465

$

29,4

53$

29

,445

$

29,4

31$

29

,422

$

29,4

14$

29

,409

$

29,4

04$

35

3,68

2$

8Pr

opos

ed C

usto

mer

Cha

rge

($/M

onth

)A-

1.L1

950

0$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

50

0$

9

Prop

osed

Non

-Fue

l Ene

rgy

Cha

rge

(NFV

C) (

$/kW

h)A-

2.L1

90.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

210

b/A-

2.L2

00.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

511

Prop

osed

Dem

and

Cha

rge

(GC

C) (

$/kW

)A-

1.L1

816

.91

$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

12c/

OAT

T Sc

h 7

1.07

$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.07

$

13c/

OAT

T Sc

h 1

0.03

7$

0.

0370

$

0.03

70$

0.

0370

$

0.03

70$

0.

0370

$

0.03

70$

0.

0370

$

0.03

70$

0.

0370

$

0.03

70$

0.

0370

$

14To

tal C

ost a

t Cur

rent

Rat

es23

3,82

0$

212,

656

$

240,

523

$

307,

850

$

273,

494

$

273,

327

$

281,

562

$

251,

875

$

275,

769

$

351,

592

$

279,

877

$

28

4,81

8$

3,

267,

160

$

15

Cur

rent

Rat

e C

alcu

latio

n: (3

) + [

(1) *

(4 +

5) +

(2) *

(6) ]

* 1

,000

+ (7

)16

Tota

l Cos

t at P

ropo

sed

Rat

ese/

500,

975

$

47

8,69

9$

50

0,97

5$

49

3,54

9$

50

0,97

5$

49

3,54

9$

50

0,97

5$

50

0,97

5$

49

3,54

9$

50

0,97

5$

49

3,54

9$

500,

975

$

5,95

9,71

9$

17Pr

opos

ed R

ate

Cal

cula

tion:

(8) +

[ ((

2)*2

4hrs

*#da

ys*0

.4) *

(9+1

0) +

(2) *

(11+

12+1

3) ]

* 1,

000

18D

iffer

ence

L16

- L14

267,

155

$

26

6,04

4$

26

0,45

2$

18

5,69

9$

22

7,48

1$

22

0,22

2$

21

9,41

3$

24

9,10

0$

21

7,78

1$

14

9,38

3$

21

3,67

2$

216,

157

$

2,69

2,55

9$

TAM

PA E

LEC

TRIC

CO

MPA

NY

Sche

dule

A-1

2 S

tate

men

t BG

/BH

Actu

al a

nd E

stim

ated

Bill

ings

at C

urre

nt a

nd P

ropo

sed

Rat

es

Cur

rent

Fue

l Ene

rgy

Cha

rge

($/k

Wh)

Prop

osed

Fue

l Ene

rgy

Cha

rge

(FPP

C) (

$/kW

h)

Prop

osed

Fue

l Ene

rgy

Cha

rge

(FPP

C) (

$/kW

h)

Exis

ting

OAT

T Tr

ansm

issi

on R

ate(

$/kW

)

Exis

ting

OAT

T Tr

ansm

issi

on R

ate(

$/kW

)Ex

istin

g O

ATT

Sche

dulin

g &

Dis

patc

h Se

rvic

e($/

kW)

Cur

rent

Fue

l Ene

rgy

Cha

rge

($/k

Wh)

Exis

ting

OAT

T Sc

hedu

ling

& D

ispa

tch

Serv

ice(

$/kW

)

66


2009

Act

ual D

ata

Line

Des

crip

tion

Not

esR

efer

ence

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Tota

l

City

of W

auch

ula

(incl

. Tra

nsm

issi

on W

heel

ing)

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Tota

l1

Net

Ene

rgy

for L

oad

(MW

h):

PR S

ch5,

003

4,43

64,

737

4,72

15,

756

6,18

16,

265

6,54

66,

223

5,88

94,

523

4,76

665

,046

2Bi

lling

Dem

and

(MW

)PR

Sch

1514

1010

1313

1313

1313

109

3C

urre

nt C

usto

mer

Cha

rge

($/M

onth

)Ta

riff

367

$

36

7$

36

7$

36

7$

36

7$

36

7$

36

7$

36

7$

36

7$

36

7$

36

7$

367

$

4,40

4$

4C

urre

nt N

on-F

uel E

nerg

y C

harg

e ($

/kW

h)Ta

riff

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

0.00

554

5a/

Tarif

f0.

0586

30.

0586

30.

0586

30.

0586

30.

0494

10.

0494

10.

0494

10.

0494

10.

0494

10.

0494

10.

0494

10.

0494

16

Cur

rent

Dem

and

Cha

rge

incl

. Tra

nsm

issi

on ($

/kW

)c/

Tarif

f9.

42$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.42

$

9.

42$

7

Prio

r Per

iod

Fuel

Adj

ustm

ent T

rue-

up C

harg

eTa

riff

22,2

0522

,213

22,1

7822

,140

22,1

1322

,104

22,0

9822

,088

22,0

8022

,075

22,0

7122

,072

265,

437

$

8Pr

opos

ed C

usto

mer

Cha

rge

($/M

onth

)A-

1.L1

950

0$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

500

$

50

0$

9

Prop

osed

Non

-Fue

l Ene

rgy

Cha

rge

(NFV

C) (

$/kW

h)A-

2.L1

90.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

20.

0054

210

b/A-

2.L2

00.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

50.

0461

511

Prop

osed

Dem

and

Cha

rge

(GC

C) (

$/kW

)A-

1.L1

816

.91

$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

16.9

1$

12c/

OAT

T Sc

h 7

1.07

$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.

07$

1.07

$

13c/

OAT

T Sc

h 1

0.03

7$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

0.

037

$

14

Exis

ting

Tran

smis

sion

Whe

elin

gd/

PEF

OAT

T1.

908

1.90

81.

908

1.90

81.

908

1.90

81.

908

1.90

81.

908

1.90

81.

908

1.90

815

Tota

l Cos

t at C

urre

nt R

ates

482,

748

$

44

1,56

7$

42

5,14

6$

41

6,54

5$

46

9,29

6$

48

1,84

5$

48

6,64

3$

50

3,01

6$

48

4,69

4$

46

9,91

6$

36

5,17

7$

373,

067

$

5,39

9,66

0$

16C

urre

nt R

ate

Cal

cula

tion:

(3) +

[ (1

) * (4

+ 5

) + (2

) * (6

) ] *

1,0

00 +

(7)

17To

tal C

ost a

t Pro

pose

d R

ates

d/55

2,80

4$

513,

404

$

453,

398

$

436,

631

$

551,

377

$

572,

494

$

577,

224

$

593,

706

$

575,

855

$

566,

206

$

432,

998

$

43

3,97

0$

6,

260,

066

$

18

Prop

osed

Rat

e C

alcu

latio

n: (8

) + [

(1) *

(9 +

10)

+ (2

) * (1

1 +

12 +

13

+ 14

) ] *

1,0

0019

Diff

eren

ceL1

7 - L

1570

,056

$

71

,837

$

28,2

53$

20

,086

$

82,0

81$

90

,649

$

90,5

80$

90

,689

$

91,1

61$

96

,290

$

67,8

21$

60

,903

$

860,

406

$

Not

es:

a/Ef

fect

ive

Janu

ary

31, 2

009-

May

6, 2

009:

Bas

e Fu

el E

nerg

y C

harg

e of

$0.

0215

9/kW

h pl

us F

uel A

djus

tmen

t Cla

use

Rat

e of

$0.

0370

4/kW

hEf

fect

ive

May

7, 2

009-

Dec

embe

r 31,

200

9: B

ase

Fuel

Ene

rgy

Cha

rge

of $

0.02

159/

kWh

plus

Fue

l Adj

ustm

ent C

laus

e R

ate

of $

0.02

782/

kWh

b/Ba

se F

uel E

nerg

y C

harg

e of

0.0

4615

/kW

h ba

sed

on 2

009

actu

al d

ata.

Mon

thly

fuel

cha

rge

will

var

y ba

sed

on a

ctua

l fue

l exp

ense

.c/

Tam

pa E

lect

ric's

tran

smis

sion

rate

(Lin

e 12

) and

sch

edul

ing

& di

spat

ch (L

ine

13) i

s bu

ndle

d in

Cur

rent

Dem

and

Rat

e (L

ine

6) s

o it

is n

otin

clud

ed in

cal

cula

tion

of (L

ine

15) T

otal

Cos

t at C

urre

nt R

ates

.d/

The

com

paris

on ra

te fo

r City

of W

achu

la in

clud

es tr

ansm

issi

on fo

r whe

elin

g. R

ate

is b

ased

on

Prog

ress

Ene

rgy

Flor

ida'

s cu

rren

t OAT

T ra

tes,

Sch

edul

es 1

,2 &

7.

e/Th

e pr

opos

ed 4

0% lo

ad fa

ctor

has

bee

n ap

plie

d in

the

calc

ulat

ion

of th

e to

tal c

ost.

Actu

al a

nd E

stim

ated

Bill

ings

at C

urre

nt a

nd P

ropo

sed

Rat

es

TAM

PA E

LEC

TRIC

CO

MPA

NY

Exis

ting

OAT

T Sc

hedu

ling

& D

ispa

tch

Serv

ice(

$/kW

)Ex

istin

g O

ATT

Tran

smis

sion

Rat

e($/

kW)

Prop

osed

Fue

l Ene

rgy

Cha

rge

(FPP

C) (

$/kW

h)

Cur

rent

Fue

l Ene

rgy

Cha

rge

($/k

Wh)

Sch

edul

e A-

12 S

tate

men

t BG

/BH

67


tampa electric website · docket no. er10-2061-000 exhibit no. tec-100 filed: 07/30/2010 amended:...

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