tampa electric website · docket no. er10-2061-000 exhibit no. tec-100 filed: 07/30/2010 amended:...
TRANSCRIPT
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
16
17
18
19
20
21
22
23
24
25
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
AMENDED: 08/12/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
AMENDED: 08/12/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
AMENDED: 08/12/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
AMENDED: 08/12/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
DOCKET NO. ER10-2061-000 EXHIBIT NO. TEC-100 FILED: 07/30/2010
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
Page
1 o
f 10
S UM
MA
RY
OF
TE
STIM
ON
Y E
XPE
RIE
NC
E
AL
AN
C. H
EIN
TZ
#
JU
RIS
DIC
TIO
N
CA
SE O
R
DO
CK
ET
NO
. U
TIL
ITY
/OR
GA
NIZ
AT
ION
IN
ITIA
TIN
G P
RO
CE
ED
ING
CL
IEN
T
APP
RO
XIM
AT
E
DA
TE
SUB
JEC
T M
AT
TE
R
1 FE
RC
ER
95-8
36-0
00
Mai
ne P
ublic
Ser
vice
Com
pany
M
aine
Pub
lic S
ervi
ce
Com
pany
19
95
Rat
es, T
erm
s and
Con
ditio
ns fo
r O
pen
Acc
ess T
rans
mis
sion
Se
rvic
es
2 FE
RC
ER
95-8
54-0
00
Ken
tuck
y U
tiliti
es C
ompa
ny
Ken
tuck
y U
tiliti
es C
ompa
ny
1995
R
ates
, Ter
ms a
nd C
ondi
tions
for
Ope
n A
cces
s Tra
nsm
issi
on
Serv
ices
3 FE
RC
ER
95-1
686-
000
ER96
-496
-000
N
orth
east
Util
ities
Ser
vice
C
ompa
ny
Nor
thea
st U
tiliti
es S
ervi
ce
Com
pany
19
96
Rat
es, T
erm
s and
Con
ditio
ns fo
r O
pen
Acc
ess T
rans
mis
sion
Se
rvic
es
4 FE
RC
ER
96--
58-0
00
Alle
ghen
y Po
wer
Ser
vice
s C
orpo
ratio
n A
llegh
eny
Pow
er S
ervi
ces
Cor
pora
tion
1995
& 1
996
Rat
es, T
erm
s and
Con
ditio
ns fo
r O
pen
Acc
ess T
rans
mis
sion
Se
rvic
es
5 FE
RC
O
A96
-138
-000
C
onso
lidat
ed E
diso
n C
ompa
ny
of N
ew Y
ork,
Inc.
C
onso
lidat
ed E
diso
n C
ompa
ny o
f New
Yor
k, In
c.
1997
R
ates
, Ter
ms a
nd C
ondi
tions
for
Ope
n A
cces
s Tra
nsm
issi
on
Serv
ices
6 FE
RC
ER
96-1
208-
000
Inte
rsta
te P
ower
Com
pany
In
ters
tate
Pow
er C
ompa
ny
1996
R
ates
, Ter
ms a
nd C
ondi
tions
for
Ope
n A
cces
s Tra
nsm
issi
on
Serv
ices
7 B
ritis
h C
olum
bia
Util
ities
C
omm
issi
on
B
ritis
h C
olum
bia
Hyd
ro a
nd
Pow
er A
utho
rity
Bon
nevi
lle P
ower
A
dmin
istra
tion
1997
R
ates
, Ter
ms a
nd C
ondi
tions
for
Ope
n A
cces
s Tra
nsm
issi
on
Serv
ices
30
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-101WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 1 OF 10
Page
2 o
f 10
#
JUR
ISD
ICT
ION
C
ASE
OR
D
OC
KE
T N
O.
UT
ILIT
Y/O
RG
AN
IZA
TIO
N
INIT
IAT
ING
PR
OC
EE
DIN
G
C
LIE
NT
A
PPR
OX
IMA
TE
D
AT
E
SU
BJE
CT
MA
TT
ER
8 FE
RC
ER
98-1
438-
000
EC98
-24-
000
Cin
cinn
ati G
as &
Ele
ctric
C
ompa
ny, e
t al.
(Mid
wes
t In
depe
nden
t Sys
tem
Ope
rato
r)
Mid
wes
t ISO
Tra
nsm
issi
on
Ow
ners
19
98 &
199
9 R
ates
, Ter
ms a
nd C
ondi
tions
for
Mid
wes
t ISO
Tar
iff
9 FE
RC
EC
98-2
770-
000
ER98
-277
0-00
0 ER
98-2
786-
000
Am
eric
an E
lect
ric P
ower
C
ompa
ny, I
nc. a
nd C
entra
l &
Sout
hwes
t Cor
pora
tion
Mid
wes
t Ind
epen
dent
Sy
stem
Ope
rato
r Tr
ansm
issi
on O
wne
rs
1999
R
easo
nabl
enes
s of t
he c
ondi
tions
to
be p
lace
d on
the
mer
ging
par
ties
10
Illin
ois
Com
mer
ce
Com
mis
sion
99-0
117
Com
mon
wea
lth E
diso
n C
ompa
ny
Com
mon
wea
lth E
diso
n C
ompa
ny
1998
C
ost o
f ser
vice
for R
etai
l D
istri
butio
n Se
rvic
es T
ariff
11
FER
C
ER99
-311
0-00
0 N
evad
a Po
wer
Com
pany
N
evad
a Po
wer
Com
pany
19
98
Rat
es, T
erm
s and
Con
ditio
ns fo
r O
pen
Acc
ess T
rans
mis
sion
Se
rvic
es
12
FER
C
ER99
-441
5-00
0 Ill
inoi
s Pow
er C
ompa
ny
Illin
ois P
ower
Com
pany
19
99
Rat
es, T
erm
s and
Con
ditio
ns fo
r O
pen
Acc
ess T
rans
mis
sion
Se
rvic
es
13
FER
C
ER99
-447
0-00
0 C
omm
onw
ealth
Edi
son
Com
pany
C
omm
onw
ealth
Edi
son
Com
pany
19
99
Rat
es, T
erm
s and
Con
ditio
ns fo
r O
pen
Acc
ess T
rans
mis
sion
Se
rvic
es
14
U.S
. Dis
trict
C
ourt,
FL
92-3
5-C
IV-O
RL-
3A22
Fl
orid
a M
unic
ipal
Pow
er
Age
ncy
vs. F
lorid
a Po
wer
and
Li
ght C
ompa
ny
Flor
ida
Pow
er a
nd L
ight
C
ompa
ny
1999
R
ates
, Ter
ms a
nd C
ondi
tions
for
Net
wor
k Se
rvic
e in
an
anti-
trust
ca
se
15
U.S
. Cou
rt of
Fe
dera
l Cla
ims,
DC
97-2
68C
C
arol
ina
Pow
er &
Lig
ht
Com
pany
vs.
U.S
. Dep
artm
ent
of E
nerg
y
Car
olin
a Po
wer
& L
ight
C
ompa
ny
1999
C
ost r
ecov
ery
of D
econ
tam
inat
ion
& D
ecom
mis
sion
ing
Fund
A
sses
smen
ts
31
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-101WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 2 OF 10
Page
3 o
f 10
#
JUR
ISD
ICT
ION
C
ASE
OR
D
OC
KE
T N
O.
UT
ILIT
Y/O
RG
AN
IZA
TIO
N
INIT
IAT
ING
PR
OC
EE
DIN
G
C
LIE
NT
A
PPR
OX
IMA
TE
D
AT
E
SU
BJE
CT
MA
TT
ER
16
FER
C
ER98
-496
-006
ER
98-2
160-
004
San
Die
go G
as &
Ele
ctric
D
yneg
y 19
99
Rat
es fo
r Mus
t Run
uni
ts
17
FER
C
ER00
-980
-000
B
ango
r Hyd
ro E
lect
ric
Com
pany
B
ango
r Hyd
ro E
lect
ric
Com
pany
19
99
Rat
es, T
erm
s and
Con
ditio
ns fo
r O
pen
Acc
ess T
rans
mis
sion
Se
rvic
es
18
Mai
ne P
ublic
U
tiliti
es
Com
mis
sion
99-1
85
Ban
gor H
ydro
Ele
ctric
C
ompa
ny
Ban
gor H
ydro
Ele
ctric
C
ompa
ny
2000
R
ates
, Ter
ms a
nd C
ondi
tions
for
Ope
n A
cces
s Tra
nsm
issi
on
Serv
ices
19
FER
C
EL00
-98-
000,
et a
l. D
yneg
y Po
wer
Mar
ketin
g, In
c,
et a
l. D
yneg
y Po
wer
Mar
ketin
g,
Inc.
20
00
Nex
us b
etw
een
fuel
and
em
issi
ons
cost
s and
the
mar
ket p
rices
in
Cal
iforn
ia
20
Illin
ois
Com
mer
ce
Com
mis
sion
No.
01-
0423
C
omm
onw
ealth
Edi
son
Com
pany
C
omm
onw
ealth
Edi
son
Com
pany
20
01
Dire
ct, R
ebut
tal a
nd S
urre
butta
l:
Cos
t of s
ervi
ce fo
r Ret
ail
Dis
tribu
tion
Serv
ices
Tar
iff
21
FER
C
ER01
-299
2 C
omm
onw
ealth
Edi
son
Com
pany
C
omm
onw
ealth
Edi
son
Com
pany
20
01
Rat
es, T
erm
s and
Con
ditio
ns fo
r O
pen
Acc
ess T
rans
mis
sion
Se
rvic
es
22
FER
C
ER01
-123
.004
M
idw
est I
SO T
rans
mis
sion
O
wne
rs
Mid
wes
t ISO
Tra
nsm
issi
on
Ow
ners
20
01
Supe
r Reg
ion
Adj
ustm
ent f
or th
e M
ISO
/AR
TO S
uper
Reg
ion
23
FER
C
ER01
-299
9 Ill
inoi
s Pow
er C
ompa
ny
Illin
ois P
ower
Com
pany
20
01
Rat
es, T
erm
s and
Con
ditio
ns fo
r O
pen
Acc
ess T
rans
mis
sion
Se
rvic
es
24
FER
C
ER01
-314
2, e
t. al
M
idw
est I
SO
Mid
wes
t ISO
Tra
nsm
issi
on
Ow
ners
20
01
Rev
ised
trea
tmen
t of N
etw
ork
Upg
rade
s
32
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-101WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 3 OF 10
Page
4 o
f 10
#
JUR
ISD
ICT
ION
C
ASE
OR
D
OC
KE
T N
O.
UT
ILIT
Y/O
RG
AN
IZA
TIO
N
INIT
IAT
ING
PR
OC
EE
DIN
G
C
LIE
NT
A
PPR
OX
IMA
TE
D
AT
E
SU
BJE
CT
MA
TT
ER
25
FER
C
ER01
-314
2, e
t. al
M
idw
est I
SO
Mid
wes
t ISO
Tra
nsm
issi
on
Ow
ners
20
01
Unc
erta
intie
s tha
t sup
port
a hi
gher
R
OE
26
FER
C
EL00
0-95
-045
, et.a
l Sa
n D
iego
Gas
& E
lect
ric
Com
pany
v. S
elle
rs o
f Ene
rgy
and
Anc
illar
y Se
rvic
e In
to
Mar
kets
Ope
rate
d by
the
CA
LISO
…
Dyn
egy,
Mira
nt, R
elia
nt a
nd
Will
iam
s 20
01 &
200
2 C
ostin
g of
em
issi
ons a
nd st
art-u
p co
sts
27
FER
C
EC
02-2
3 &
ER
02-
320
Tran
s-El
ect,
Inc.
, et.
al
Tran
s-El
ect,
Inc.
20
01 &
200
2 Su
ppor
t of r
ates
and
rate
mak
ing
met
hodo
logy
for n
ew tr
ansm
issi
on
com
pany
28
FER
C
Si
the
New
Bos
ton,
LLC
Si
the
New
Bos
ton,
LLC
20
01 &
200
2 C
ost o
f Ser
vice
for M
ust R
un U
nit
29
FER
C
RM
01-1
2 FE
RC
Tec
hnic
al C
onfe
renc
e Se
Tran
s 20
02
Allo
catio
n of
FTR
s/C
RR
s
30
FER
C
EL02
-111
M
idw
est I
SO &
PJM
M
idw
est I
SO T
rans
mis
sion
O
wne
rs
2002
Th
roug
h an
d O
ut R
ates
31
FER
C
ER02
-259
5 M
idw
est I
SO
Mid
wes
t ISO
Tra
nsm
issi
on
Ow
ners
20
02
Cos
t Allo
catio
n fo
r FTR
and
M
arke
t Adm
inis
tratio
n
32
FER
C
ER03
-37
Sier
ra P
acifi
c R
esou
rces
Si
erra
Pac
ific
and
Nev
ada
Pow
er
2003
A
ncill
ary
Serv
ice
Rat
es
33
FER
C
ER03
-626
Em
pire
Dis
trict
Ele
ctric
Co.
Em
pire
Dis
trict
Ele
ctric
Co.
20
03
Cos
t of S
ervi
ce; W
hole
sale
R
equi
rem
ents
Cus
tom
ers
34
FER
C
EL-0
2-25
-001
, et.
al
Inte
rmou
ntai
n, H
oly
Cro
ss,
Yam
pa a
nd A
quila
Pu
blic
Ser
vice
Co.
of
Col
orad
o 20
03
Fuel
Adj
ustm
ent C
laus
e
33
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-101WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 4 OF 10
Page
5 o
f 10
#
JUR
ISD
ICT
ION
C
ASE
OR
D
OC
KE
T N
O.
UT
ILIT
Y/O
RG
AN
IZA
TIO
N
INIT
IAT
ING
PR
OC
EE
DIN
G
C
LIE
NT
A
PPR
OX
IMA
TE
D
AT
E
SU
BJE
CT
MA
TT
ER
35
FER
C
ER03
-959
Ex
elon
Fra
min
gham
LLC
, et a
l. Ex
elon
Fra
min
gham
LLC
, et
al.
2003
Pr
oduc
tion
Cos
t of S
ervi
ce
36
FER
C
ER03
-118
7 M
idW
est G
ener
atio
n, L
LC
Com
mon
wea
lth E
diso
n 20
03
Bla
ck S
tart
Rat
es
37
FER
C
ER03
-122
3 M
onta
na M
egaw
atts
I, L
LC, e
t al
. M
onta
na M
egaw
att
2003
Pr
oduc
tion
Form
ula
Rat
es
38
FER
C
ER03
-133
5 C
omm
onw
ealth
Edi
son
Com
mon
wea
lth E
diso
n 20
03
Tran
smis
sion
Tar
iff R
ates
39
FER
C
ER03
-135
4 B
lack
Hill
s Pow
er C
ompa
ny, e
t al
. B
lack
Hill
s Pow
er C
ompa
ny,
et a
l. 20
03
Join
t tra
nsm
issi
on T
ariff
Rat
es
40
FER
C
ER03
-132
8 Si
erra
Pac
ific
Res
ourc
es
Nev
ada
Pow
er
2003
Tr
ansm
issi
on T
ariff
Rat
es
41
FER
C
EL02
-111
, et.
Al
Mid
wes
t ISO
and
PJM
Tr
ansm
issi
on O
wne
rs
Mid
wes
t ISO
Tra
nsm
issi
on
Ow
ners
20
04
Long
-term
Tra
nsm
issi
on P
ricin
g Pl
an
42
FER
C
ER05
-14
Sier
ra P
acifi
c R
esou
rces
Si
erra
Pac
ific
2004
Tr
ansm
issi
on T
ariff
Rat
es
43
FER
C
ER05
-26
Mira
nt K
enda
ll, L
LC
Mira
nt K
enda
ll, L
LC
2004
R
elia
bilit
y M
ust R
un A
gree
men
t an
d R
ates
44
Illin
ois
Com
mer
ce
Com
mis
sion
No.
04-0
779
NIC
OR
Gas
Com
pany
N
ICO
R G
as C
ompa
ny
2004
D
istri
butio
n Se
rvic
e Em
bedd
ed
Cos
t of S
ervi
ce S
tudy
45
FER
C
Er05
-163
M
ilfor
d Po
wer
Com
pany
LLC
M
ilfor
d Po
wer
Com
pany
LL
C
2004
R
elia
bilit
y M
ust R
un A
gree
men
t an
d R
ates
34
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-101WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 5 OF 10
Page
6 o
f 10
#
JUR
ISD
ICT
ION
C
ASE
OR
D
OC
KE
T N
O.
UT
ILIT
Y/O
RG
AN
IZA
TIO
N
INIT
IAT
ING
PR
OC
EE
DIN
G
C
LIE
NT
A
PPR
OX
IMA
TE
D
AT
E
SU
BJE
CT
MA
TT
ER
46
FER
C
EL02
-111
, et.
al
Mid
wes
t ISO
and
PJM
Tr
ansm
issi
on O
wne
rs
Mid
wes
t ISO
Tra
nsm
issi
on
Ow
ners
20
04
Seam
s Elim
inat
ion
47
FER
C
EL00
-95,
et.
al
SDG
&E
V. S
elle
rs, e
t al.
Portl
and
Gen
eral
Ele
ctric
C
ompa
ny
2005
C
alifo
rnia
Ref
und
Proc
eedi
ng
48
FER
C
ER05
-447
M
idw
est I
SO
Mid
wes
t ISO
Tra
nsm
issi
on
Ow
ners
20
05
Sche
dule
10
& 1
7 R
ecov
ery
for
Gra
ndfa
ther
ed A
gree
men
ts
49
FER
C
EL02
-111
, et.
al
Mid
wes
t ISO
and
PJM
Tr
ansm
issi
on O
wne
rs
Mid
wes
t ISO
Tra
nsm
issi
on
Ow
ners
20
05
Seam
s Elim
inat
ion
50
FER
C
ER05
-860
W
hitin
g C
lean
Ene
rgy
Whi
ting
Cle
an E
nerg
y 20
05
Cos
t Bas
ed P
ower
Rat
es
51
FER
C
ER05
-903
C
on. E
d. E
nerg
y M
ass.,
Inc.
C
on. E
d. E
nerg
y M
ass.,
Inc.
20
05
Rel
iabi
lity
Mus
t Run
Agr
eem
ent
and
Rat
es
52
FER
C
EL02
-111
, et.
al
Mid
wes
t ISO
and
PJM
Tr
ansm
issi
on O
wne
rs
Mid
wes
t ISO
Tra
nsm
issi
on
Ow
ners
20
05
Seam
s Elim
inat
ion
53
FER
C
ER05
-105
0 A
mer
Gen
Ene
rgy
Com
pany
, L.
L.C
. A
mer
Gen
Ene
rgy
Com
pany
, L.
L.C
. 20
05
Rea
ctiv
e po
wer
cha
rges
54
Illin
ois
Com
mer
ce
Com
mis
sion
No.
05-0
597
Com
mon
wea
lth E
diso
n C
o.
Com
mon
wea
lth E
diso
n C
o.
2005
D
istri
butio
n Se
rvic
e Em
bedd
ed
Cos
t of S
ervi
ce S
tudy
55
FER
C
ER05
-117
9 B
erks
hire
Pow
er C
ompa
ny, L
LCB
erks
hire
Pow
er C
ompa
ny,
LLC
20
05
Rel
iabi
lity
Mus
t Run
Agr
eem
ent
and
Rat
es
35
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-101WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 6 OF 10
Page
7 o
f 10
#
JUR
ISD
ICT
ION
C
ASE
OR
D
OC
KE
T N
O.
UT
ILIT
Y/O
RG
AN
IZA
TIO
N
INIT
IAT
ING
PR
OC
EE
DIN
G
C
LIE
NT
A
PPR
OX
IMA
TE
D
AT
E
SU
BJE
CT
MA
TT
ER
56
FER
C
ER05
-124
3 B
asin
Ele
ctric
Pow
er
Coo
pera
tive
Bas
in E
lect
ric P
ower
C
oope
rativ
e 20
05
Rev
ised
Tra
nsm
issi
on C
ost o
f Se
rvic
e
57
FER
C
ER05
-130
4 &
ER05
-130
5 M
ystic
I, L
LC a
nd M
ystic
D
evel
opm
ent,
LLC
M
ystic
I, L
LC a
nd M
ystic
D
evel
opm
ent,
LLC
20
05
Rel
iabi
lity
Mus
t Run
Agr
eem
ent
and
Rat
es
58
FER
C
ER05
-273
M
idw
est I
SO
Mid
wes
t ISO
Tra
nsm
issi
on
Ow
ners
20
05
Prop
er P
ricin
g fo
r Reg
iona
l Non
-fir
m R
edire
cts
59
FER
C
ER05
-515
PH
I and
BG
E PH
I and
BG
E 20
05
Tran
smis
sion
For
mul
a R
ates
60
FER
C
EL05
-19
Sout
hwes
tern
Pub
lic S
ervi
ce
Com
pany
So
uthw
este
rn P
ublic
Ser
vice
C
ompa
ny
2005
Pr
oduc
tion
rate
s and
Fue
l A
djus
tmen
t Cla
use,
61
FER
C
ER06
-427
M
ystic
Dev
elop
men
t, LL
C
Mys
tic D
evel
opm
ent,
LLC
20
06
Rel
iabi
lity
Mus
t Run
Agr
eem
ent
and
Rat
es
62
FER
C
ER06
-822
Fo
re R
iver
Dev
elop
men
t, LL
C
Fore
Riv
er D
evel
opm
ent,
LLC
20
06
Rel
iabi
lity
Mus
t Run
Agr
eem
ent
and
Rat
es
63
FER
C
ER06
-819
C
onso
lidat
ed E
diso
n En
ergy
M
assa
chus
etts
, Inc
C
onso
lidat
ed E
diso
n En
ergy
M
assa
chus
etts
, Inc
20
06
Rel
iabi
lity
Mus
t Run
Agr
eem
ent
and
Rat
es
64
FER
C
ER07
-169
A
mer
en E
nerg
y M
arke
ting
Com
pany
A
mer
en E
nerg
y M
arke
ting
Com
pany
20
06
Anc
illar
y se
rvic
e ra
tes
65
FER
C
ER06
-154
9 D
uque
sne
Ligh
t Com
pany
D
uque
sne
Ligh
t Com
pany
20
06
Tran
smis
sion
For
mul
a R
ates
66
FER
C
ER07
-170
A
mer
en E
nerg
y, In
c.
Am
eren
Ene
rgy,
Inc.
20
06
Anc
illar
y se
rvic
e ra
tes
67
FER
C
ER06
-787
Id
aho
Pow
er
Idah
o Po
wer
20
06 &
200
7 Tr
ansm
issi
on F
orm
ula
Rat
es
36
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-101WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 7 OF 10
Page
8 o
f 10
#
JUR
ISD
ICT
ION
C
ASE
OR
D
OC
KE
T N
O.
UT
ILIT
Y/O
RG
AN
IZA
TIO
N
INIT
IAT
ING
PR
OC
EE
DIN
G
C
LIE
NT
A
PPR
OX
IMA
TE
D
AT
E
SU
BJE
CT
MA
TT
ER
68
FER
C
ER07
-562
Tr
ans-
Alle
ghen
y In
ters
tate
Lin
e C
ompa
ny
Tran
s-A
llegh
eny
Inte
rsta
te
Line
Com
pany
20
07
Tran
smis
sion
For
mul
a R
ates
69
FER
C
ER07
-583
C
omm
onw
ealth
Edi
son
Com
mon
wea
lth E
diso
n 20
07
Tran
smis
sion
For
mul
a R
ates
70
FER
C
ER07
-117
1 A
rizon
a Pu
blic
Ser
vice
Co.
A
rizon
a Pu
blic
Ser
vice
Co.
20
07
Tran
smis
sion
For
mul
a R
ates
71
Illin
ois
Com
mer
ce
Com
mis
sion
No.
07-
0566
C
omm
onw
ealth
Edi
son
Co.
C
omm
onw
ealth
Edi
son
Co.
20
07
Dis
tribu
tion
Serv
ice
Embe
dded
C
ost o
f Ser
vice
Stu
dy
72
FER
C
ER07
-137
1 Si
erra
Pac
ific
Res
ourc
es
Sier
ra P
acifi
c R
esou
rces
20
07
Tran
smis
sion
Rat
es
73
FER
C
ER08
-281
O
klah
oma
Gas
& E
lect
ric
Okl
ahom
a G
as &
Ele
ctric
20
07
Tran
smis
sion
For
mul
a R
ates
74
FER
C
ER08
-313
So
uthw
este
rn P
ublic
Ser
vice
So
uthw
este
rn P
ublic
Ser
vice
20
07
Tran
smis
sion
For
mul
a R
ates
75
FER
C
ER08
-386
Po
tom
ac-A
ppal
achi
an
Tran
smis
sion
Hig
hlin
e, L
LC
Poto
mac
-App
alac
hian
Tr
ansm
issi
on H
ighl
ine,
LLC
20
07
Tran
smis
sion
For
mul
a R
ates
76
FER
C
ER08
-374
A
tlant
ic P
ath
15, L
LC
Atla
ntic
Pat
h 15
, LLC
20
07
Tran
smis
sion
Rat
es
77
Illin
ois
Com
mer
ce
Com
mis
sion
No.
08-
0363
N
ICO
R G
as C
ompa
ny
NIC
OR
Gas
Com
pany
20
08
Dis
tribu
tion
Serv
ice
Embe
dded
C
ost o
f Ser
vice
Stu
dy
78
FER
C
ER08
-951
PS
EG E
nerg
y R
esou
rces
&
Trad
e, L
LC
PSEG
Ene
rgy
Res
ourc
es &
Tr
ade,
LLC
20
08
Rea
ctiv
e Po
wer
Cha
rges
79
FER
C
ER08
-123
3 Pu
blic
Ser
vice
Gas
& E
lect
ric
Com
pany
Pu
blic
Ser
vice
Gas
&
Elec
tric
Com
pany
20
08
Tran
smis
sion
For
mul
a R
ates
37
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-101WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 8 OF 10
Page
9 o
f 10
#
JUR
ISD
ICT
ION
C
ASE
OR
D
OC
KE
T N
O.
UT
ILIT
Y/O
RG
AN
IZA
TIO
N
INIT
IAT
ING
PR
OC
EE
DIN
G
C
LIE
NT
A
PPR
OX
IMA
TE
D
AT
E
SU
BJE
CT
MA
TT
ER
80
FER
C
ER08
-145
7 PP
L El
ectri
c U
tiliti
es C
orp.
PP
L El
ectri
c U
tiliti
es C
orp.
20
08
Tran
smis
sion
For
mul
a R
ates
81
FER
C
ER08
-158
4 B
lack
Hill
s Pow
er
Bla
ck H
ills P
ower
20
08
Tran
smis
sion
For
mul
a R
ates
82
FER
C
ER08
-160
0 B
asin
Ele
ctric
Pow
er C
oop
Bas
in E
lect
ric P
ower
Coo
p 20
08
Tran
smis
sion
Rat
es
83
FER
C
ER09
-36
Prai
rie W
ind
Tran
smis
sion
, LLC
Prai
rie W
ind
Tran
smis
sion
, LL
C
2008
Tr
ansm
issi
on F
orm
ula
Rat
es
84
FER
C
ER09
-35
Tallg
rass
Tra
nsm
issi
on, L
LC
Tallg
rass
Tra
nsm
issi
on, L
LC
2008
Tr
ansm
issi
on F
orm
ula
Rat
es
85
FER
C
ER09
-75
Pion
eer T
rans
mis
sion
, LLC
Pi
onee
rs T
rans
mis
sion
, LLC
20
08
Tran
smis
sion
For
mul
a R
ates
86
FER
C
ER09
-255
N
ebra
ska
Publ
ic P
ower
Dis
trict
N
ebra
ska
Publ
ic P
ower
D
istri
ct
2008
Tr
ansm
issi
on F
orm
ula
Rat
es
87
FER
C
ER09
-528
IT
C G
reat
Pla
ins,
LLC
IT
C G
reat
Pla
ins,
LLC
20
09
Tran
smis
sion
For
mul
a R
ates
88
Illin
ois
Com
mer
ce
Com
mis
sion
ER08
-053
2 C
omm
onw
ealth
Edi
son
Co.
C
omm
onw
ealth
Edi
son
Co.
20
09
Dis
tribu
tion
Serv
ice
Embe
dded
C
ost o
f Ser
vice
Stu
dy
89
FER
C
ER08
-370
& E
L09-
22
Mis
sour
i Riv
er E
nerg
y Se
rvic
es
& M
ISO
O
tter T
ail P
ower
Co.
20
09
Form
ula
Tran
smis
sion
Rat
e
90
FER
C
ER10
-152
PP
L El
ectri
c U
tiliti
es C
orp.
PP
L El
ectri
c U
tiliti
es C
orp.
20
09
Rev
ised
Dep
reci
atio
n M
etho
d
91
FER
C
ER09
-172
7 A
LLET
E, IN
C
ALL
ETE.
INC
20
09
Form
ula
Tran
smis
sion
Rat
e
92
FER
C
ER10
-230
K
CP&
L K
CP&
L 20
09
Form
ula
Tran
smis
sion
Rat
es
38
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-101WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 9 OF 10
Page
10
of 1
0 #
JU
RIS
DIC
TIO
N
CA
SE O
R
DO
CK
ET
NO
. U
TIL
ITY
/OR
GA
NIZ
AT
ION
IN
ITIA
TIN
G P
RO
CE
ED
ING
CL
IEN
T
APP
RO
XIM
AT
E
DA
TE
SUB
JEC
T M
AT
TE
R
93
FER
C
ER10
-455
A
mer
en E
nerg
y M
arke
ting
Com
pany
A
mer
en E
nerg
y M
arke
ting
Com
pany
20
09
Rea
ctiv
e Po
wer
Rat
es
94
FER
C
ER10
-516
SC
E&G
SC
E&G
20
10
Form
ula
Tran
smis
sion
Rat
es
95
FER
C
ER10
-962
U
nion
Ele
ctric
Com
pany
U
nion
Ele
ctric
Com
pany
20
10
Rea
ctiv
e Po
wer
Rat
es
96
FER
C
ER10
-114
9 FP
&L
FP&
L 20
10
Form
ula
Tran
smis
sion
Rat
es
39
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-101WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 10 OF 10
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
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 1 OF 28
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 ) $0.00/kW
Notes:a/ Transmission Loss Factor (TLF) A-2, Note b/4 0.9842
Schedule A-1 Determination of Demand-Related Costs and Generation Capacity ChargeTwelve Months Ended December 31, 2009 -- Actual
TAMPA ELECTRIC COMPANY
41
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 2 OF 28
Line Description Reference Amount1 Annual Salary & Benefits Company Records 312,724$
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.
TAMPA ELECTRIC COMPANY
Schedule A-1.1 Monthly Customer Charge Twelve Months Ended December 31, 2009 -- Actual
42
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 3 OF 28
TAMPA ELECTRIC COMPANY
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 ) $0.00000/kWh
Notes:a/ Revenue credits are associated with fuel, margins & variable O&M dollars included in FM-1, pg 311. i
b/ System Average Transmission Losses (based on FERC Annual A/B Filing, Schedule C):1)Transmission System Losses, incl Generator Step-UpTransformer Losses 365,829 2) Total Annual Energy Output to Line Composed of: Total of all EnergyAvailable, plus Wheeling Rec'd, less Wheeling Del'd Losses 23,186,308 3) System Average Transmission Loss Percentage ((Note b L1/L2)*100) 1.58 4) Transmission Loss Factor (TLF) ((100 - Note b L3)/100) 0.9842
Schedule A-2 Determination of Energy-Related Costs and Energy ChargesTwelve Months Ended December 31, 2009 -- Actual
43
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 4 OF 28
Line Description Notes Reference Energy
Fuel & Purchased Power Charge1 555 Purchased Power (PP) a/, b/ FM-1, p327.m 2 501 Fuel a/ FM-1, p320.5.b 3 518 Fuel a/ FM-1, p320.25.b 4 547 Fuel a/ FM-1, p321.63.b 5 Subtotal Fuel & Purchased Power Charge (Sum Lines 1 to 4) -
Revenue Credits6 Off-System Sales/Revenue Credits c/ FM-1,p311.i - 7 Ancillary Service Revenues8 Energy Imbalance Service Ancillary Sch. 4 - 9 Generator Imbalance Service Ancillary Sch 9 -
10 Subtotal Revenue Credits (Sum Lines 6 to 9) -
11 Subtotal Fuel & PP less Revenue Credits e/ L5 - L10 -
12 Total Energy less Non-Requirements Sales for Resale a/ FM-1, p401b.41.b - 41.c 0 MWh
13 Fuel & Purchased Power Charge ($/kWh) (L11 / L12) / 1000 $0.0000/kWh
14 d/ (L13/TLF) $0.0000/kWh
Notes:a/ Reference is to FERC Form No. 1, which is annual. The amounts on this schedule are monthly. They will tie to annual totals by year end, except
for true-ups or adjustments.b/ 555 Purchased Power (FM-1, p327). The "Other" component is classified to demand or non-fuel energy dependent on source.c/ Reference is to FERC Form No. 1, which is annual. The amounts on this schedule are monthly. The credits will include fuel, margins, &
variable O&M when applicable.d/ The Transmission Loss Factor (TLF), Schedule A-2, is reported annually in Tampa Electric's FERC A/B Filing, Schedule C and will be updated
in the Annual Update Process.e/ Prior Period Adjustments will be included when applicable.
Total Demand Other: Classified
as Demand Other:Classified
as Non-Fuel Energy Energy
Line Description Reference (a) (b) (c) (d) (e)Company InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany InvoicesCompany Invoices
Add additional invoices as necessary.
Total Sum Invoices - - - - -
Monthly Detail, Purchased Power
Schedule A-2.1 Determination of Monthly Energy-Related Costs and Energy Charges
TAMPA ELECTRIC COMPANY
Month of _____________
Fuel & Purchased Power Charge ("FPPC") ($/kWh) (Adjusted by TLF)
44
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 5 OF 28
TAMPA ELECTRIC COMPANY
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
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 6 OF 28
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
TAMPA ELECTRIC COMPANY
46
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 7 OF 28
TAMPA ELECTRIC COMPANY
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
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 8 OF 28
TAMPA ELECTRIC COMPANY
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
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 9 OF 28
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
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 10 OF 28
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
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 11 OF 28
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
Prep
aym
ents
Mis
cella
neou
s
SER
P-Su
pple
men
tal E
xecu
tive
Ret
irem
ent P
lan
Fibe
r Opt
ic
51
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 12 OF 28
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
TAMPA ELECTRIC COMPANY
52
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 13 OF 28
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$
TAMPA ELECTRIC COMPANY
Schedule A-4.3 Generator Step-Up Units (GSU)Twelve Months Ended December 31, 2009 -- Actual
53
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 14 OF 28
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
TAMPA ELECTRIC COMPANY
Schedule A-4.4 Capital Additions Placed in ServiceTwelve Months Ended December 31, 2010 -- Projected
54
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 15 OF 28
TAMPA ELECTRIC COMPANY
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
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 16 OF 28
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
TAMPA ELECTRIC COMPANY
Schedule A-5.1 Classification of Fixed and Variable Production ExpensesTwelve Months Ended December 31, 2009 -- Actual
56
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 17 OF 28
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
TAMPA ELECTRIC COMPANY
Twelve Months Ended December 31, 2009 -- Actual
57
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 18 OF 28
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.
TAMPA ELECTRIC COMPANY
Schedule A-6.1 Regulatory Commission ExpensesTwelve Months Ended December 31, 2009 -- Actual
58
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 19 OF 28
TAMPA ELECTRIC COMPANY
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
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 20 OF 28
TAMPA ELECTRIC COMPANY
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
Schedule A-7 Production-Related Depreciation Expense and Applied Depreciation RatesTwelve Months Ended December 31, 2009 -- Actual
60
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 21 OF 28
TAMPA ELECTRIC COMPANY
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
Schedule A-7 Production-Related Depreciation Expense and Applied Depreciation RatesTwelve Months Ended December 31, 2009 -- Actual
61
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 22 OF 28
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)
TAMPA ELECTRIC COMPANY
Twelve Months Ended December 31, 2009 -- Actual
62
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 23 OF 28
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
TAMPA ELECTRIC COMPANY
Twelve Months Ended December 31, 2009 -- Actual
63
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 24 OF 28
TAMPA ELECTRIC COMPANY
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
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 25 OF 28
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 -
6 Difference L5 - L4 -
7 A-2 (of Prior Year Formula), L14
8 A-2, L14 -
9 Difference L8 - L7 -
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)
1/12 of Amount on Line 6
Interest = (b) * (c) * (g)
Total including Interest (g) + (h)
1/12 of Amount on Line 9
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 > -
TAMPA ELECTRIC COMPANY
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
Current Year Formula(Populated with Prior Year FM-1 Data)
Reference
Prior Year Annual Non-Fuel Energy Charge Excluding Over/(Under) Collection and Interest
Current Year Formula(Populated with Prior Year FM-1 Data)
Prior Year Annual Production Fuel and Purchased Power Cost Excluding Over/(Under) Collection and Interest
65
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 26 OF 28
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(
$/kW
)
66
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 27 OF 28
2009
Act
ual D
ata
Line
Des
crip
tion
Not
esR
efer
ence
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Tota
l
City
of W
auch
ula
(incl
. Tra
nsm
issi
on W
heel
ing)
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Tota
l1
Net
Ene
rgy
for L
oad
(MW
h):
PR S
ch5,
003
4,43
64,
737
4,72
15,
756
6,18
16,
265
6,54
66,
223
5,88
94,
523
4,76
665
,046
2Bi
lling
Dem
and
(MW
)PR
Sch
1514
1010
1313
1313
1313
109
3C
urre
nt C
usto
mer
Cha
rge
($/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
DOCKET NO. ER10-2061-000EXHIBIT NO. TEC-102WITNESS: HEINTZFILED: 07/30/2010AMENDED: 08/12/2010PAGE 28 OF 28