DATE:	March 1, 2012
TO:	Office of Commission Clerk (Cole)
FROM:	Division of Economic Regulation (Ollila, D. Buys, Cicchetti, Higgins, Wu) Office of the General Counsel (Klancke)
RE:	Docket No. 110131-EI – Petition for approval of 2011 depreciation study and annual dismantlement accrual amounts by Tampa Electric Company.
AGENDA:	03/13/12 – Regular Agenda – Proposed Agency Action – Interested Persons May Participate
COMMISSIONERS ASSIGNED:			All Commissioners
PREHEARING OFFICER:			Brisé
CRITICAL DATES:			None
SPECIAL INSTRUCTIONS:			None
FILE NAME AND LOCATION:			S:\PSC\ECR\WP\110131.RCM.DOC

 

 Case Background

Rules 25-6.0436(8)(a) and 25-6.04364(3), Florida Administrative Code (F.A.C.), require investor-owned utilities to file a comprehensive depreciation study and site-specific dismantlement study for each fossil-fueled generating site at least once every four years from the submission date of the previously filed study.  On April 27, 2011, Tampa Electric Company (Tampa Electric or Company) filed its regular depreciation and dismantlement studies in compliance with this rule.  The Commission has jurisdiction pursuant to Sections 350.115 and 366.05, Florida Statutes (F.S.).

Discussion of Issues

Issue 1: 

 Should currently prescribed depreciation rates and provision for dismantlement of Tampa Electric Company be revised?

Recommendation: 

 Yes.  A review of the Company’s plans and activities indicates a need for revision to the currently prescribed depreciation rates and provision for dismantlement.  (Ollila)

Staff Analysis: 

 Tampa Electric’s last comprehensive depreciation study was filed on April 27, 2007.  By Order No. PSC-08-0014-PAA-EI,[1] the Commission approved revised depreciation rates and provision for dismantlement, effective January 1, 2007.  A review of the Company’s activity data indicates the need to revise the depreciation rates and dismantlement accrual.

Issue 2: 

 What should be the implementation date for new depreciation rates and the provision for dismantlement?

Recommendation: 

 Staff recommends approval of Tampa Electric’s proposed January 1, 2012 implementation date for revised depreciation rates and provision for dismantlement.  (Ollila)

Staff Analysis: 

 Rule 25-6.0436(6)(b), F.A.C., requires that the data submitted in a depreciation study, including plant and reserve balances or company estimates, “[S]hall be brought to the effective date of the proposed rates.”  The supporting data and calculations provided by Tampa Electric match an implementation date of January 1, 2012.

Issue 3: 

 What are the appropriate depreciation rates?

Recommendation: 

 The appropriate depreciation rates are contained in Attachment A.  Staff recommends that if investment is added to the Phillips Station, previously approved depreciation rates, as contained in Order No. PSC-08-0014-PAA-EI, should be applied until the next depreciation study.  Staff recommends that the Big Bend SCR investments and associated accumulated depreciation be transferred to separate accounts.  Staff recommends that Tampa Electric file a petition for approval to initiate depreciation prior to the in-service date of any proposed units.  (Ollila, Higgins, Wu)

Staff Analysis: 

 Staff’s recommendations are the result of a comprehensive review of Tampa Electric’s study.  As part of its review, staff issued data requests and participated in an informal meeting with the Company.  Staff notes that only the accounts where staff and the Company initially differed on depreciation parameters are addressed in this staff analysis.  As a result of the review and analytical process, staff and Tampa Electric now agree on lives, net salvages, and the resulting depreciation rates for all accounts.  Attachment A contains a comparison of current rates and components to staff recommended rates and components. 

 

Production Plant

            Tampa Electric has five generating stations: Big Bend, Bayside, Polk, Phillips, and City of Tampa (also known as the Partnership Station).  The stations, each comprised of two or more units, include coal-fired steam, combined cycle, combustion turbine, an integrated gasification combined cycle, and internal combustion diesel units. 

            Phillips Station has been on long-term standby since September 2009.  The Station’s two units are in operable condition but have not been used because of the higher cost of fuel (#6 oil) required to operate the units as compared to natural gas and coal.  As of December 31, 2011, the units were fully recovered.  Tampa Electric does not expect to add any investment to the Phillips units; however, the Company agrees that in the event assets are added, depreciation rate(s) should be applied to those assets.  Tampa Electric proposes that previously approved rates be used if assets are added in the future.  Staff agrees with this proposal.  Staff recommends that if investment is added to the Phillips Station, previously approved depreciation rates, as contained in Order No. PSC-08-0014-PAA-EI,[2] should be applied until the next depreciation study.

 

Both subsections (5)(a) and (5)(c) of Rule 25-6.04361, F.A.C., (stratification rule) require that each production plant account be stratified “in accord with . . . [its] potential life patterns.” Stratifying components of plant investment into categories that, on average, have expected lives of about the same number of years, enables recovery provisions to be more closely matched to the life characteristics of the investment categories used to generate electric power.  The Company’s stratification life categories are long, medium, and short. As part of its review for this depreciation study, Tampa Electric reviewed the life categories, and moved $76 million from the long category to the medium and short categories for the Big Bend Station.

Subsequent to the 2007 study, Tampa Electric added four Selective Catalytic Reduction (SCR) units to Big Bend Units 1-4.  The SCR investment was added to existing accounts within the Big Bend units.  As part of the current study, the Company stratified the SCR investment contained in property records in accord with the stratification rule.  Similar to prior treatment of the Flue Gas Desulfurization (FGD) units associated with the Big Bend Station, Tampa Electric proposes to transfer the SCR investment and accumulated depreciation to newly created accounts.  Costs associated with SCR units are recovered through the Environmental Cost Recovery Clause (ECRC).  Transferring the SCR units to new accounts would be consistent with the separation of the FGD units, would permit a more accurate determination of the true age and other parameters, and would also prevent mixing these assets with non-ECRC assets.  Staff recommends that the Big Bend SCR investments and associated accumulated depreciation be transferred to separate accounts.

According to Tampa Electric’s 2011 Ten-Year Site Plan, filed on April 1, 2011, Schedule 9, combustion turbine units have been proposed with in-service dates between 2013-2014, prior to the due date of the next depreciation study.  The Company’s preference is to wait until a generating unit is approved and under construction before depreciation rates are established.  Staff agrees with the Company’s preference.  Staff recommends that Tampa Electric file a petition for approval to initiate depreciation prior to the in-service date of any proposed units.

General Plant

 

            Staff reviewed the information pertinent to Tampa Electric’s general plant accounts in its study, and the Company’s responses to staff data requests.  Based on this information, staff proposed depreciation parameters for each of the depreciable accounts listed below.  The Company has agreed with all of staff’s proposed parameters, which include average service life, average remaining life, net salvage percentage, average age, and curve shape.  Staff and the Company are also in agreement with respect to the amortization term for each of the amortizable accounts listed below.

 

Depreciable Accounts

Account 390.00 – Structures and Improvements

Account 397.25 – Communication Equipment-Fiber

Account 392.02 – Light Trucks-Energy Delivery  

Account 392.03 – Heavy Trucks-Energy Delivery

Account 392.04 – Medium Trucks-Energy Delivery

Account 392.12 – Light Trucks-Energy Supply

Account 392.13 – Heavy Trucks-Energy Supply

Account 392.14 – Medium Trucks-Energy Supply

 

Amortizable Accounts

Account 391.01 – Office Furniture Equipment

Account 391.02 – Computer Equipment-Work Stations

Account 391.03 – Data Handling Equipment

Account 391.04 – Computer Equipment-Mainframe

Account 393.00 – Stores Equipment

Account 394.00 – Tool/Shop Equipment

Account 395.00 – Laboratory Equipment

Account 396.00 – Power Operated Equipment

Account 397.00 – Communication Equipment

Account 398.00 – Miscellaneous Equipment

 

Reserve Transfers

            As part of its review of Tampa Electric’s depreciation study, staff reviewed the book reserve position for each account.  Based on staff’s recommended life and salvage inputs for this study, staff determined the Company’s theoretical or calculated reserve.   The difference between an account’s book and theoretical reserve may be described as a positive or negative imbalance, or as a surplus or deficiency.  When negative or positive imbalances occur, corrective transfers among accounts should be made as quickly as possible, unless this action prevents the Company from earning a fair and reasonable return on its investments. 

            For electric utilities such as Tampa Electric, corrective reserve transfers ideally are made within each function (e.g., production or transmission) but not between functions.  Jurisdictional separations, purchased power agreements, or other lease arrangements may be affected by reserve transfers between functions.  For example, customers may purchase transmission service under the Company’s Federal Energy Regulatory Commission (FERC)-regulated Open Access Transmission Tariff.  A reserve transfer to or from the transmission function may have a cost or benefit on the cost basis of the rate.

            As part of its depreciation study (and following guidance from staff in prior studies), Tampa Electric proposed reserve transfers.  The reserve transfers include the Company’s proposal to transfer an amount sufficient to bring the remaining negative reserve balance of ($188,820) for the previously-retired Gannon Station to zero.  Staff has thoroughly reviewed Tampa Electric’s proposed reserve transfers as well as its explanations as provided in response to staff’s data requests.  Staff agrees with the Company’s proposed reserve transfers, which are contained in Table 3-1.  Staff monitors Tampa Electric’s reserve activity (additions, retirements, and adjustments) on an annual basis.  The annual review includes preparation and submission of data requests as necessary.

Table 3-1: Proposed Reserve Transfers*

 

*Some numbers may not total exactly because of rounding.
Depreciation Expense

            Staff’s recommended depreciation rates result in an increase to depreciation expense of $4,246,075.[3]  The primary driver of the increased depreciation expense is the Big Bend Station.  Generating units are studied on a life span basis, whereby the overall unit retires at one time (final retirement), although there will be interim additions and retirements throughout the years of operation of the unit.  In an investment account, the timing of additions and retirements plays a role in determining how fast the account ages.  The age of an account helps to determine the remaining life of the account, which directly translates into the depreciation rate.  When investment is added to a generating unit (such as an SCR unit), the average service life of the investment is directly tied to the remaining life of the generating unit.  This means that if investment with a 30-year average service life is added to a unit with 25 years remaining, then the investment will have an average service life no longer than 25 years.  This shortens the time period for the recovery of the investment.  According to Public Utilities Depreciation Practices,

            A general characteristic of property studied using the life span method is the       gradual increase in the depreciation rate as the property ages.  Plant additions subsequent to the initial placement usually exceed the interim retirements, even           though the additions may replace plant retired, because they are made at a higher           cost than the plant retired.  The result is a shorter average service life of the life          span property.[4]

            Factors that contribute to the overall increase in expense include the general characteristics of lifespan property, the shorter lifespans of the SCR units, the proposed transfers of the SCR units to separate accounts, and the impacts of the units’ operating history (e.g., retirements and additions).               

Conclusion

In conclusion, staff recommends the appropriate depreciation rates as contained in Attachment A.  Staff recommends that if investment is added to the Phillips Station, previously approved depreciation rates, as contained in Order No. PSC-08-0014-PAA-EI, should be applied until the next depreciation study.  Staff recommends that the Big Bend SCR investments and associated accumulated depreciation be transferred to separate accounts.  Staff recommends that Tampa Electric file a petition for approval to initiate depreciation prior to the in-service date of any proposed units.

Issue 4: 

 What is the appropriate annual accrual for dismantlement?

Recommendation: 

 The Commission should approve a total annual provision for fossil fuel dismantlement of $1,186,094, as shown on Attachment C.  This represents a decrease in the annual provision for fossil fuel dismantlement of $150,892. This accrual reflects current estimates of dismantlement costs on a site-specific basis using a November 2011 inflation forecast and a 15 percent contingency factor.  (Higgins, Buys)

Staff Analysis: 

 

The Commission established the methodology for accruing the costs for dismantlement of fossil-fueled production plants by Order No. 24741.[5]  The methodology, codified in Rule 25-6.04364, F.A.C., is dependent on three factors: estimated base costs for dismantlement, projected inflation, and a contingency factor.  Investor-owned electric utilities are required to file site-specific dismantlement studies at least once every four years from the submission date of the previous study unless otherwise required by the Commission.

Dismantlement accruals are based on current cost estimates, escalated to future costs as of the estimated date of dismantlement.  The future costs, less accumulated dismantlement reserves, are discounted over the remaining life of each plant and plant site.  The contingency factor is designed to cover uncertainty in the dismantlement cost estimates.  The factor is comprised of pricing and scope of omission contingencies.  The pricing contingency provides a level of confidence that the estimates are reasonable.  The scope omission contingency  acknowledges the conceptual nature of the base cost estimates and the difficulty in obtaining quantity and weight records.  Rule 25-6.04364, F.A.C., defines the contingency costs as a specific provision for unforeseeable elements of cost within the defined project scope. Tampa Electric has proposed increasing its currently approved contingency factor from 10 percent to 15 percent.  Staff notes a contingency factor of 15 percent is within the range approved by the Commission for other electric utilities.[6] Staff will continue to monitor the Company’s contingency factor in its subsequent dismantlement studies for reasonableness.

Tampa Electric retained Burns & McDonnell (BMcD) to conduct its 2011 dismantlement study.  The plants included in this study are natural gas, fuel oil, and coal-fired generating facilities.  The study is meant to provide a total cost estimate to dismantle each of the aforementioned facilities at the end of its useful life. 

            Tampa Electric’s currently approved annual accrual for fossil fuel dismantlement is $1,336,986.  In its 2011 study, the Company is requesting a decrease in its annual accrual to $1,117,920.  However, when the Company's study is updated to reflect the November 2011 inflation forecast, this accrual increases slightly to $1,186,094.  The net decrease comes as the total cost to dismantle Tampa Electric’s fossil fleet has increased.  However, this base cost increase has been partially offset by two significant factors.  First, the value for scrap metals has increased substantially since the Company’s 2007 study.  Second, the current study reflects a decreased inflation forecast.  The differences in dismantlement base cost estimates (net of scrap metal values) between Tampa Electric’s current and last study are presented in Table 4-1.

             

 

 

            The inflation factors as of November 2011 used to derive the proposed annual accrual are lower than the September 2007 inflation factors that were used to arrive at the currently approved annual accrual.

 

            Tampa Electric has proposed a series of reserve transfers among the accounts of its dismantlement reserve.  These transfers are presented on Attachment D.  Staff has reviewed the transfer proposals and recommend they be adopted.

 

            Staff recommends that the Commission approve a total annual provision for fossil fuel dismantlement of $1,186,094, as shown on Attachment C.  This represents a decrease in the current annual provision for fossil fuel dismantlement of $150,892.  This accrual reflects current estimates of dismantlement costs on a site-specific basis using a November 2011 inflation forecast and a 15 percent contingency factor. 

 

 

 

Issue 5: 

 Should the current amortization of investment tax credits (ITCs) and flow back of excess deferred income taxes (EDITs) be revised to reflect the approved depreciation rates?

Recommendation: 

 Yes.  The current amortization of ITCs and the flowback of EDITs should be revised to match the actual recovery periods for the related property.  The Company should file detailed calculations of the revised ITC amortization and flowback of EDITs at the same time it files its surveillance report covering the period ending December 31, 2012.  (Cicchetti)

Staff Analysis: 

  In earlier issues, staff has recommended approval of revised depreciation rates for the Company, to be effective January 1, 2012, which reflect changes to most accounts’ remaining lives to be effective January 1, 2012.  Revising a utility's book depreciation lives generally results in a change in its rate of ITC amortization and flowback of EDITs in order to comply with the normalization requirements of the Internal Revenue Code (IRC or Code) set forth in sections 168(f)(2) and (i)(9), IRC sections 167(l) and 46(f),[7] Federal Tax Regulations under the Code sections,[8] and section 203(e) of the Tax Reform Act of 1986 (the Act). [9]

Staff, the Internal Revenue Service (IRS), and independent outside auditors look at a company's books and records, and the orders and rules of the jurisdictional regulatory authorities to determine if the books and records are maintained in the appropriate manner.  The books are also reviewed to determine if they are in compliance with the regulatory guidelines in regard to normalization.  Therefore, staff recommends the current amortization of ITCs and the flowback of EDITs be revised to reflect the remaining useful lives that underlie staff’s proposed depreciation rates.

            Section 46(f)(6) of the Code states that “the amortization of ITC should be determined by the period of time actually used in computing depreciation expense for ratemaking purposes and on the regulated books of the utility.”[10]  Since staff is recommending changes to the Company’s remaining lives, it is also important to change the amortization of ITCs to avoid violation of the provisions of IRC section 46 and its underlying Treasury Regulations.  The consequence of an ITC normalization violation is a repayment of unamortized ITC balances to the IRS.

            Section 203(e) of the 1986 Act prohibits rapid flow back of depreciation-related (protected) EDITs to the utility’s customers.  Further, Rule 25-14.013, F.A.C., Accounting for Deferred Income Taxes Under SFAS 109, generally prohibits EDITs from being written off any faster than allowed under the Act.  The Act, ASC 740,[11] and Rule 25-14.013, F.A.C,  regulate the flowback of EDITs.  Therefore, staff recommends that the flowback of EDITs be adjusted to comply with the Act, ASC 740, and Rule 25-14.013, F.A.C.

Issue 6: 

 Should this docket be closed?

Recommendation: 

 Yes.  If no person whose substantial interests are affected by the proposed agency action files a timely request for a hearing within 21 days of the issuance of the order, this docket should be closed upon the issuance of a consummating order.  (Klancke)

Staff Analysis: 

 If no person whose substantial interests are affected files a timely request for a hearing within 21 days, no further action will be required and this docket should be closed upon the issuance of a consummating order.

 

 

Attachment B
Comparison of Expenses
				Current				Staff Proposed
Account	Account Title			Depreciation		Annual		Depreciation	Annual	Change In
Number				Rate		Expense		Rate	Expense	Expense
				(%)		($)		(%)	($)	($)
	BIG BEND STATION
31140	BB Common			2.0		3,694,794		2.9	5,357,451	1,662,657
31240	BB Common			2.6		2,246,516		3.4	2,937,752	691,236
31440	BB Common			1.8		127,052		2.3	162,344	35,292
31540	BB Common			3.0		657,763		3.7	811,241	153,478
31640	BB Common			3.1		293,949		4.2	398,254	104,305
31141	BB Unit  No. 1			1.4		109,273		2.0	156,105	46,832
31241	BB Unit  No. 1			3.3		3,656,648		4.0	4,432,301	775,653
31441	BB Unit  No. 1			2.5		830,555		3.5	1,162,777	332,222
31541	BB Unit  No. 1			2.5		404,238		3.5	565,933	161,695
31641	BB Unit  No. 1			1.2		12,473		2.9	30,143	17,670
31142	BB Unit  No. 2			1.6		127,075		2.0	158,844	31,769
31242	BB Unit  No. 2			3.1		2,884,884		3.7	3,443,249	558,365
31442	BB Unit  No. 2			2.5		1,148,227		3.8	1,745,305	597,078
31542	BB Unit  No. 2			2.5		341,379		3.3	450,620	109,241
31642	BB Unit  No. 2			2.0		13,603		3.0	20,404	6,801
31143	BB Unit  No. 3			1.2		182,529		1.8	273,793	91,264
31243	BB Unit  No. 3			2.6		3,539,484		3.5	4,764,690	1,225,206
31443	BB Unit  No. 3			1.8		750,819		3.2	1,334,790	583,971
31543	BB Unit  No. 3			2.5		590,048		3.6	849,669	259,621
31643	BB Unit  No. 3			2.7		38,375		3.0	42,639	4,264
31144	BB Unit  No. 4			1.4		871,534		1.8	1,120,544	249,010
31244	BB Unit  No. 4			2.4		5,779,822		3.0	7,224,778	1,444,956
31444	BB Unit  No. 4			2.0		1,916,324		2.8	2,682,853	766,529
31544	BB Unit  No. 4			2.1		941,752		3.2	1,435,050	493,298
31644	BB Unit  No. 4			1.7		99,022		2.5	145,620	46,598
31146	No. 1 & 2  FGD System			2.6		330,328		2.9	368,442	38,114
31246	No. 1 & 2  FGD System			2.9		1,799,398		3.3	2,047,591	248,193
31546	No. 1 & 2  FGD System			3.3		300,515		3.5	318,728	18,213
31646	No. 1 & 2  FGD System			2.5		44,498		2.9	51,617	7,119
31145	No. 3 & 4  FGD System			1.5		335,037		2.0	446,716	111,679
31245	No. 3 & 4  FGD System			2.3		3,641,379		2.5	3,958,020	316,641
31545	No. 3 & 4  FGD System			2.1		486,318		3.1	717,898	231,580
31645	No. 3 & 4  FGD System			2.0		15,040		3.2	24,065	9,025
31151	No. 1 SCR System			2.1		475,671		4.1	928,692	453,021
31251	No. 1 SCR System			2.6		1,177,853		4.3	1,947,988	770,135
31551	No. 1 SCR System			3.0		453,020		4.8	724,833	271,813
31651	No. 1 SCR System			3.1		26,007		4.1	34,396	8,389
31152	No. 2 SCR System			1.4		352,924		3.5	882,310	529,386
31252	No. 2 SCR System			3.2		1,581,235		4.0	1,976,544	395,309
31552	No. 2 SCR System			2.5		397,861		4.1	652,492	254,631
31652	No. 2 SCR System			1.2		11,503		3.7	35,469	23,966
31153	No. 3 SCR System			1.2		260,273		3.1	672,372	412,099
31253	No. 3 SCR System			2.6		1,105,255		3.9	1,657,883	552,628
31553	No. 3 SCR System			2.5		342,274		4.0	547,638	205,364
31653	No. 3 SCR System			2.7		22,266		3.4	28,039	5,773
31154	No. 4 SCR System			1.4		236,002		2.4	404,574	168,573
31254	No. 4 SCR System			2.3		758,911		3.8	1,253,853	494,942
31554	No. 4 SCR System			2.1		223,483		3.9	415,039	191,556
31654	No. 4 SCR System			1.7		11,695		3.3	22,702	11,007
31647	Big Bend Amortizable Tools			14.3		317,298		14.3	317,298	0
34144	BB CT No. 4			4.3		302,759		2.6	183,064	(119,695)
34244	BB CT No. 4			4.3		124,666		3.6	104,371	(20,295)
34344	BB CT No. 4			4.3		1,086,371		4.0	1,010,578	(75,793)
34544	BB CT No. 4			4.3		267,140		4.0	248,503	(18,637)
34644	BB CT No. 4			0.0		0		0.0	0	0
	BAYSIDE POWER STATION
34130	BP Common		2.3			1,601,966		2.3	1,601,966	0
34230	BP Common		2.5			463,103		2.5	463,103	0
34330	BP Common		2.9			981,518		3.2	1,083,054	101,536
34530	BP Common		4.3			501,256		4.2	489,599	(11,657)
34630	BP Common		3.4			302,559		3.2	284,761	(17,798)
34131	BP Unit No. 1		2.3			506,264		2.5	550,287	44,023
34231	BP Unit No. 1		2.9			2,069,597		2.9	2,069,597	0
34331	BP Unit No. 1		4.0			7,684,403		4.2	8,068,623	384,220
34531	BP Unit No. 1		3.2			1,045,480		3.2	1,045,480	0
34631	BP Unit No. 1		2.5			31,443		2.7	33,958	2,515
34132	BP Unit No. 2		2.3			598,216		2.5	650,235	52,019
34232	BP Unit No. 2		2.9			2,771,277		2.9	2,771,277	0
34332	BP Unit No. 2		3.9			10,412,424		4.1	10,946,395	533,971
34532	BP Unit No. 2		3.1			1,255,371		3.1	1,255,371	0
34632	BP Unit No. 2		2.6			39,462		2.8	42,497	3,035
34133	BP CT No. 3		4.3			195,296		2.6	118,086	(77,210)
34233	BP CT No. 3		4.3			80,416		3.6	67,325	(13,091)
34333	BP CT No. 3		4.3			700,768		4.0	651,877	(48,891)
34533	BP CT No. 3		4.3			172,320		4.0	160,298	(12,022)
34633	BP CT No. 3		0.0			0		0.0	0	0
34134	BP CT No. 4		4.3			194,952		2.6	117,878	(77,074)
34234	BP CT No. 4		4.3			80,274		3.6	67,206	(13,068)
34334	BP CT No. 4		4.3			699,532		4.0	650,728	(48,804)
34534	BP CT No. 4		4.3			172,016		4.0	160,015	(12,001)
34634	BP CT No. 4		0.0			0		0.0	0	0
34135	BP CT No. 5		4.3			293,422		2.6	177,418	(116,004)
34235	BP CT No. 5		4.3			120,821		3.6	101,152	(19,669)
34335	BP CT No. 5		4.3			1,052,869		4.0	979,413	(73,456)
34535	BP CT No. 5		4.3			258,902		4.0	240,839	(18,063)
34635	BP CT No. 5		0.0			0		0.0	0	0
34136	BP CT No. 6		4.3			292,673		2.6	176,965	(115,708)
34236	BP CT No. 6		4.3			120,513		3.6	100,894	(19,619)
34336	BP CT No. 6		4.3			1,050,181		4.0	976,913	(73,268)
34536	BP CT No. 6		4.3			258,241		4.0	240,224	(18,017)
34636	BP CT No. 6		0.0			0		0.0	0	0
34637	Bayside Amortizable Tools		14.3			0		14.3	0	0
	POLK POWER STATION
34180	PK Common		2.3			1,525,339		2.2	1,459,020	(66,319)
34280	PK Common		2.2			95,171		3.7	160,061	64,890
34380	PK Common		2.0			48,236		2.2	53,059	4,823
34580	PK Common		2.4			46,540		2.9	56,236	9,696
34680	PK Common		2.2			17,557		2.4	19,154	1,597
34181	PK Unit No. 1		2.5			1,168,430		2.5	1,168,430	0
34281	PK Unit No. 1		3.4			7,945,121		3.4	7,945,121	0
34381	PK Unit No. 1		6.4			8,160,846		4.5	5,738,095	(2,422,751)
34581	PK Unit No. 1		3.1			1,817,456		3.3	1,934,711	117,255
34681	PK Unit No. 1		3.4			175,174		3.1	159,718	(15,456)
34182	PK CT No. 2		2.7			58,025		2.7	58,025	0
34282	PK CT No. 2		2.9			35,788		3.3	40,724	4,936
34382	PK CT No. 2		7.6			2,103,222		4.4	1,217,655	(885,567)
34582	PK CT No. 2		2.9			480,517		2.8	463,948	(16,569)
34682	PK CT No. 2		2.8			4,850		3.5	6,062	1,212
34183	PK CT No. 3		2.6			268,764		2.6	268,764	0
34283	PK CT No. 3		2.9			33,721		2.9	33,721	0
34383	PK CT No. 3		6.2			2,391,293		4.6	1,774,185	(617,108)
34583	PK CT No. 3		3.0			273,577		3.0	273,577	0
34683	PK CT No. 3		2.9			12,554		3.1	13,420	866
34184	PK CT No. 4		4.3			240,092		2.4	134,005	(106,087)
34284	PK CT No. 4		4.3			92,285		3.2	68,678	(23,607)
34384	PK CT No. 4		4.3			960,159		4.1	915,500	(44,659)
34584	PK CT No. 4		4.3			218,555		3.9	198,225	(20,330)
34684	PK CT No. 4		4.3			0		4.3	0	0
34185	PK CT No. 5		4.3			240,550		2.4	134,261	(106,289)
34285	PK CT No. 5		4.3			87,469		3.4	69,162	(18,307)
34385	PK CT No. 5		4.3			891,101		3.9	808,208	(82,893)
34585	PK CT No. 5		4.3			216,502		3.9	196,362	(20,140)
34685	PK CT No. 5		4.3			0		4.3	0	0
34687	Polk Amortizable Tools		14.3			138,511		14.3	138,511	0
	PHILLIPS STATION
34128	Phillips Station		3.4			322,374		0.0	0	(322,374)
34228	Phillips Station		3.0			703,076		0.0	0	(703,076)
34328	Phillips Station		3.7			772,221		0.0	0	(772,221)
34528	Phillips Station		3.5			206,059		0.0	0	(206,059)
34628	Phillips Station		4.2			27,428		0.0	0	(27,428)
	CITY OF TAMPA
34390	City of Tampa Partnership		4.5			292,435		4.3	279,438	(12,997)
	TRANSMISSION PLANT
350.01	Land Rights		2.3			215,643		1.3	121,885	(93,758)
352.00	Structures and Improvements		2.3			146,509		1.7	108,289	(38,220)
353.00	Station Equipment		2.5			6,046,432		2.3	5,562,718	(483,714)
354.00	Towers and Fixtures		2.4			102,591		2.3	98,316	(4,275)
355.00	Poles and Fixtures		4.4			7,480,757		3.6	6,120,619	(1,360,138)
356.00	Overhead Conductors and Devices		3.7			4,899,126		2.8	3,707,446	(1,191,680)
356.01	Clearing Rights-of-Way		2.0			42,212		2.0	42,212	0
357.00	Underground Conduit		1.7			60,066		1.8	63,599	3,533
358.00	Underground Conductors and Devices		2.4			168,222		2.3	161,213	(7,009)
359.00	Roads and Trails		2.2			116,617		1.5	79,512	(37,105)
	DISTRIBUTION PLANT
361.00	Structures and Improvements		2.4			61,052		1.8	45,789	(15,263)
362.00	Station Equipment		2.5			4,929,104		2.4	4,731,940	(197,164)
364.00	Poles, Towers and Fixtures		4.7			11,037,882		4.4	10,333,336	(704,546)
365.00	Overhead Conductors and Devices		3.3			7,653,292		3.1	7,189,456	(463,836)
366.00	Underground Conduit		2.0			3,285,685		1.8	2,957,116	(328,569)
367.00	Underground Conductors and Devices		3.2			6,786,654		3.0	6,362,488	(424,166)
368.00	Line Transformers		4.2			18,137,415		4.4	19,001,102	863,687
369.00	Overhead Services		3.1			2,278,231		3.4	2,498,705	220,474
369.02	Underground Services		3.3			3,728,766		2.8	3,163,802	(564,964)
370.00	Meters		6.3			4,632,788		7.2	5,294,614	661,826
373.00	Street Lighting and Signal Systems		5.2			8,512,222		5.4	8,839,615	327,393
	GENERAL PLANT
390.00	Structures & Improvements		3.5			2,830,521		2.3	1,860,057	(970,464)
397.25	Comm. Equipment		6.9			1,563,715		5.3	1,201,114	(362,601)
TRANSPORTATION EQUIPMENT
		Energy Delivery
392.02		Light Trucks			12.6	642,591		5.2	265,196	(377,395)
392.03		Heavy Trucks			5.9	1,075,610		5.1	929,764	(145,846)
392.04		Medium Trucks			7.8	69,427		6.6	58,746	(10,681)
		Energy Supply
392.12		Light Trucks			8.5	126,156		6.6	97,957	(28,199)
392.13		Heavy Trucks			5.9	30,651		3.7	19,222	(11,429)
392.14		Medium Trucks			5.7	10,688		3.3	6,188	(4,500)
		GENERAL PLANT AMORTIZED
391.01		Office Furniture and Equipment			14.3	682,258		14.3	682,258	0
391.02		Computer Equipment - Work Stations			25	3,647,936		25.0	3,647,936	0
391.03		Data Handling Equipment			14.3	85,778		14.3	85,778	0
391.04		Computer Equipment - Mainframe			20	688,941		20.0	688,941	0
393.00		Stores Equipment			14.3	0		14.3	0	0
394.00		Tools, Shop and Garage Equipment			14.3	1,416,957		14.3	1,416,957	0
395.00		Laboratory Equipment			14.3	0		14.3	0	0
396.00		Power Operated Equipment			14.3	1,190		14.3	1,190	0
397.00		Communication Equipment			14.3	2,078,135		14.3	2,078,135	0
398.00		Miscellaneous Equipment			14.3	63,665		14.3	63,665	0
		Totals				Current Expenses			Proposed Expenses	Difference
		TOTAL TRANS., DIST., & GEN. PLANT				105,335,485			99,586,876	(5,748,609)
		TOTAL PRODUCTION PLANT				115,823,651			125,818,334	9,994,684
		FOSSIL DISMANTLEMENT				1,336,986			1,186,094	(150,892)
		TOTAL PLANT				222,496,122			226,591,304	4,095,183