s t a t e o f m i c h i g a n before the michigan public

S T A T E O F M I C H I G A N

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application of ) THE DETROIT EDISON COMPANY for ) Reconciliation of its Power Supply ) Case No. U-_______ Cost Recovery Plan for the 12-month Period ) Ending December 31, 2004 ) In the matter of the Application of ) THE DETROIT EDISON COMPANY ) To Implement the Commission’s Final ) Case No. U-_______ Order in Case No. U-13808 Concerning, ) Inter Alia, 2004 Net Stranded Costs and the ) Provisions of Section 10a(16) and (17). )

QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

JAMES H. BYRON

THE DETROIT EDISON COMPANY QUALIFICATIONS OF JAMES H. BYRON

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Q. Please state your name and business address.

A. My name is James H. Byron. My business address is The Detroit Edison

Company 2000 Second Avenue, Detroit, Michigan 48226.

Q. Please describe your educational background.

A. I received a Bachelor of Science Degree in Electrical Engineering from Wayne

State University in 1969. I also received a Master of Science Degree in

Electrical Engineering from Wayne State University in 1971.

Q. Please describe your professional experience.

A. I began my employment in 1968 as a student in the Underground Planning

Division of the General Engineering Department of The Detroit Edison

Company (“Detroit Edison” or “Company”). This position involved assisting the

engineers in designing and laying out the underground cable system. I was

also responsible for conducting a feasibility study of converting the Detroit A.C.

network from 4.8 kV to 13.2 kV.

In 1969 I was employed as an Assistant Engineering Analyst in the Technical

Systems Planning Department where I participated in the design and

implementation of the engineering and management systems on the computer.

As an engineering analyst I assisted with or was responsible for the Bulk

Power Load Flow Program and data base operation, the Distribution Load

Flow, the Transient Stability system, the Interactive Load Flow system, Short

Circuit Study programs, the Unit Commitment Economic Dispatch system, and

various informational and engineering systems.

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While employed in Technical Systems, I cross-trained with the Economic

Studies Group of Electrical System, Data Processing Operations Department,

Transmission Planning Department and Bulk Power Transactions. These

cross-training assignments spanned approximately a four-year period. I also

served on the Automatic Meter Reading Task Force.

In 1976 I joined Bulk Power Transactions as a senior engineer. As senior

engineer, I worked on the Monroe Unit No. 2, the Trenton Channel Unit No. 8

and the River Rouge Unit No. 2 Insurance Studies, Time of Day studies, Load

Management applications of water heater controls, studies of other load

management techniques, Purchased Power and Net Interchange forecasts,

fuel forecasts and dispatch fuel costs, coal conservation dispatch, and

coordinating informational and engineering systems with various areas of the

Company.

During the summer of 1977 I was assigned to the Michigan Electric Power

Coordination Center and worked in the operations group. In June 1980 I was

promoted to the position of Interconnection Agreements Engineer. In

connection with a temporary assignment in the fall of 1983, I assisted the

outage manager on the Monroe Unit 1 scheduled outage. In April 1987, I was

promoted to the position of Senior Interconnection Agreements Engineer. In

December 1990, I was promoted to the position of Director - Operations of

Power Supply Transactions.

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In February of 1996 a new organization was created by transferring and

integrating Power Supply Transactions and the large customer marketing and

sales group from the Energy Marketing & Distribution Organization. The title of

the new organization is Customer Energy Solutions (CES). In July 1996, I was

appointed Director of Sourcing with the added responsibility for long term

resource planning.

Q. What were your responsibilities in this position?

A. As Director of Sourcing, I was responsible for the negotiation, development

and administration of interconnection operating agreements with other utility

systems. I supervised the purchasing and selling of weekly, seasonal, and

longer term power from interconnection transactions, the forecasting of

purchased power and system operation, the analysis of long term resource

requirements, the preparation of testimony with respect to both forecast and

actual purchased power and system operation, the developing and filing of

interconnection agreements and rates with the Federal Energy Regulatory

Commission (FERC), the preparation of bills for the smaller utility systems in

Michigan, and the interaction with other operating departments to maintain and

improve overall system economics and adequacy of power supply.

Additionally, I was responsible for preparation of billing data for qualified

facilities selling energy to the Company. I also served on administrative and/or

operating committees and subcommittees established with other utilities.

In December of 1996, I was appointed Director of Energy Management -

Customer Energy Solutions. My duties included developing energy

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management services for our customers, negotiating and administering

contracts, providing technical expertise of system operations for the Company,

and representing the Company on various committees with other companies.

In November of 1997, I was appointed Director of Planning & Optimization –

Operation, Planning, and Control. The title of the organization was changed

and my title became Director - Economic Operation of Power Planning &

Optimization. In June 1999, a new organization, Generation Optimization was

formed but my title and position were unchanged. My responsibilities were

negotiation, development and administration of interconnection operating

agreements with other utility systems. I supervised the purchasing and selling

of weekly, seasonal, and longer term power from interconnection transactions,

the forecasting of purchased power and system operation, the analysis of long

term resource requirements, the preparation of testimony with respect to both

forecast and actual purchased power and system operation, the developing

and filing of interconnection agreements and rates with the FERC, and the

interaction with other operating departments to maintain and improve overall

system economics and adequacy of power supply. I also served on

administrative and/or operating committees and subcommittees established

with other utilities.

In April 2001, I was appointed Manager of Generation Optimization-Power

Supply Planning. My main areas of responsibility were to: (1) direct the

planning for generation capacity and purchase power needs; (2) direct the

development of load and sales forecasts for the Company; (3) direct the

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establishment of supply reliability policies that ensure continued supply

reliability at the least possible cost; and (4) participate in regulatory

proceedings on behalf of the Company regarding matters involving power

purchases and sales and other supply related issues.

Q. What is your current position?

A. In November 2002, Generation Optimization was re-organized and the

responsibility for load forecasting was moved to the Controllers organization.

Currently, I continue to be Manger of Generation Optimization-Power Supply

Planning, retitled Manager of Generation Optimization-Power Planning &

Reliability, and my main areas of responsibility are to: (1) direct the planning

for generation capacity and purchase power needs including transmission

requirements; (2) direct the negotiation, development and administration of

interconnection operating agreements with other utility systems; (3) direct the

purchasing and selling of weekly, seasonal, and longer term power ; (4) direct

the establishment of supply reliability policies that ensure continued supply

reliability at the least possible cost; and (5) participate in regulatory

proceedings on behalf of the Company regarding matters involving power

purchases and sales, system operations, and other power supply-related

issues.

Q. Have you previously testified before the Commission?

A. Yes. I testified before the Michigan Public Service Commission (MPSC) in 27

monthly Purchased and Net Interchange Power Adjustment cases during the

period 1978 through 1982, and in the following additional cases:

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U-6488-R 1982 Fuel and Purchased and Net Interchange Power Adjustment Clause Reconciliation

U-7550 1983 Power Supply Cost Recovery Plan


U-7775-R 1984 Power Supply Cost Recovery Reconciliation






U-8789 1987 Main Electric Rate Case


U-8869-DE/ 1991 Establishing a Framework for Future Capacity U-9798 Solicitations from Qualifying Facilities

U-10102 1994 Main Electric Rate Case











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U-11726 1998 Accounting Authority Related to the Accelerated Amortization of the Fermi 2 Nuclear Plant


U-12639 Implementation of the Provisions of Section 10a(10) of 2000 PA 141

U-13350 2000-2001 Implementation of the Stranded Cost Recovery Procedure and For Approval of Net Stranded Cost Recovery Charges

U-13808 2003 Main Case & 2004 PSCR Plan


I have also testified before the FERC in the following cases:

EL02-111 FERC Investigation of the Rates For Through and Out Service under the Midwest ISO and PJM Tariffs

ER04-691/EL04-104 Midwest Independent System Operator, Inc. Public Utilities With Grandfathered Agreements in the Midwest ISO Region

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THE DETROIT EDISON COMPANY DIRECT TESTIMONY OF JAMES H. BYRON

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Q. What is the purpose of your testimony?

A. The purpose of my testimony is to present and discuss the Company's 2004

power supply system operations. This includes the Company's system

generation and purchases and third party wholesale sales of power.

Q. Are you sponsoring any exhibits?

A. Yes, I am sponsoring the following exhibits:

Exhibit No. A-1 (JHB-1) 2004 System Operation Summary

Exhibit No. A-2 (JHB-2) 2004 Electric Generation By Plant

Exhibit No. A-3 (JHB-3) 2004 Capacity Factor Summary

Exhibit No. A-4 (JHB-4) 2004 Purchases of Power and Energy Summary

Exhibit No. A-5 (JHB-5) 2004 Summary of Third Party Wholesale Power

Sales

Exhibit No. A-6 (JHB-6) 2004 Summary of Network Transmission Expense

Exhibit No. A-7 (JHB-7) 2004 Third Party Wholesale Power Sales Net

Proceeds

Q. Can you describe Exhibit No. A-1 (JHB-1)?

A. Yes. Exhibit No. A-1 (JHB-1) is a summary of the 2004 System Operations.

Shown on the exhibit are the actual energy, expense and $/MWh for system

electric generation (excluding industrial send out steam), Emission allowance

expense for oxides of nitrogen (NOx), Purchased Power energy and expense,

Third Party Wholesale Power sales energy and PSCR cost credit, and Net

System Output. Ludington losses are also shown. Net System Output is

shown with an adjustment for interruptible customers’ (R-10, SMC & LCC)

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energy utilization. The forecasted information from the 2004 Power Supply

Cost Recovery (PSCR) Plan and the variance from the Plan are also displayed

on the adjacent columns.


A. Yes. Exhibit No. A-2 (JHB-2) is a summary of the Company’s power plant

generation for 2004. Shown on the exhibit is the primary fuel type and actual

generation by plant, the forecasted generation presented in the 2004 PSCR

Plan, and the variance.


A. Yes. Exhibit No. A-3 (JHB-3) is a summary of the 2004 capacity factors for

each of the Company’s power plants and the forecasted capacity factors from

the 2004 PSCR Plan. The capacity factors are developed based upon actual

generation within a period divided by the net demonstrated capability during

that period. Also shown are the winter net demonstrated operating capabilities

of the plants, as of January 1, 2005.

Q. Did any changes occur in net demonstrated capability in 2004?

A. Yes. The net demonstrated capability of Monroe Unit 3 increased by 45 MW

from 750 MW to 795 MW (785 MW summer rating) as a result of the

installation of the dense pack turbines on the LP and HP turbines.


A. Yes. Exhibit No. A-4 (JHB-4) is a summary of 2004 Purchased Power for the

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Company. Shown on the Exhibit are the actual and forecasted energy and

expense for the specific categories of purchases.


A. Yes. Exhibit No. A-5 (JHB-5) is a summary of 2004 Third Party Wholesale

Power Sales for the Company. Shown on the Exhibit are the actual and

forecasted energy and revenue for the specific categories of sales.


A. Exhibit No. A-6 (JHB-6) is the summary of the Network Transmission Expense

for 2004 and the Network Transmission Expense incurred for the period from

November 24 through December 31, 2004. Also shown are the projected

Network Transmission Expenses from the 2004 PSCR Plan and the variance

from the plan to actual.


A. Exhibit No. A-7 (JHB-7) presents the calculation of the Third Party Wholesale

Power Sales Gross Proceeds, Third Party Wholesale Sales Production O&M

expense, Third Party Wholesale Sales Net Proceeds, and the Third Party

Wholesale Power Sales fuel and net proceeds credit for the PSCR.

Q. Can you explain the Company's 2004 system operation results?

A. Yes. Please refer to Exhibit No. A-1 (JHB-1). The net system output (NSO) of

46,149 GWh was 2,316 GWh below the forecast of 48,465 GWh.

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The actual adjusted NSO expense of $666,218,000 was $97,507,000 below

the forecast as shown on line 33. The actual and forecast expenses exclude

the sulfur dioxide (SO2) emission allowance expense and include the network

transmission expense only for the period of November 24 through December

31, 2004. In addition, the actual adjusted NSO expense only includes the fuel

and net proceeds credit for third party sales, not the total revenue. The

adjusted average NSO cost (excluding network transmission) of $14.22/MWh

was $1.31/MWh below the forecast and $0.67/MWh below the 2003 NSO cost

of $14.89/MWh as shown on line 35.

The actual system generation of 48,420 GWh was 709 GWh above the

forecast. The actual average cost of the 2004 system generation was

$12.77/MWh, which was $0.06/MWh below forecast and $0.93/MWh below the

2003 average system generation cost.

The summer of 2004 was one of the coolest on record for the Detroit

Metropolitan area. There were only two days on which temperatures reached

or exceeded 90° F compared to four days during 2003, and 24 days in 2002.

High temperatures at or above 85° F were experienced on only 11 days this

past summer. The Company only cycled the interruptible air conditioners (IAC)

on one day (August 2, 2004) for 2.5 hours during the summer.

The system peak occurred on Thursday, July 22nd, when the bundled peak

demand reached 9,591 MW and the total peak load for the Detroit Edison

service territory reached 11,357 MW (for the integrated hour ending 1700

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excluding DIG). This was the hottest day of the year as the temperature

reached 91° F.

The emission allowance expense for the NOx emissions during the NOx

emission season of May through September was $1,250,000. This amount of

expense was reasonable and prudent in that it was a result of Edison’s

economic dispatch of its units which considered various expense items,

including NOx emission allowances.

Q. What is the “PSCR Fuel and Net Proceed Credit from Third Party

Wholesale Power Sales” shown on Exhibit No. A-1 (JHB-1)?

A. The “PSCR Fuel and Net Proceeds Credit from Third Party Wholesale Power

Sales” is the gross power supply cost incurred to make the third party

wholesale power sales and energy imbalance sales, and the PSCR net

proceeds credit from Third Party Wholesale Power Sales. This credit is

developed on Exhibit No. A-7 (JHB-7).

Q. What was the effect of sales to interruptible R-10 customers and the

interruptible and buyout sales to the SMC and LCC (which have

provisions similar to the R-10) customers on the Net System Output and

associated expense?

A. Please refer to Exhibit No. A-1 (JHB-1). These R-10, SMC and LCC sales are

not PSCR sales and are not included in determining recoverable PSCR

expense. The required adjustment, a credit of incremental expense to serve

these interruptible sales, is shown on Exhibit No. A-1 (JHB-1). The

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interruptible sales under these contracts were 1,308 GWh, 100 GWh below the

forecasted amount of 1,408 GWh. The actual expense of $28,207,000 was

$11,471,000 below the forecasted expense of $39,678,000.

Q. What was the net effect of these interruptible sales adjustments?

A. The Net System Output, when adjusted for the interruptible sales was 44,842

GWh, 2,215 GWh below the forecast of 47,057 GWh. The adjusted actual

expense of $637,608,000 was $86,439,000 below the forecast. The average

adjusted PSCR cost of $14.22/MWh was $1.17/MWh below the forecast.

Q. Did the Commission Order in Case No. U-10646, which approved the

SMC contracts, address the impact on PSCR customers of an

incremental increase in SMC firm load?

A. Yes, the Commission Order in MPSC Case No. U-10646 stated: “If average

PSCR costs (i.e., PSCR costs per kWh) increase as a result of incremental

load attributable to the contracts, the added costs should be treated as any

other category of unrecovered cost created by the contract pricing.” (MPSC

Case No. U-10646, Order dated March 23, 1995, p. 20)

Q. What was the Company’s estimate of any incremental increase in SMC

and LCC firm load that could, in turn, result in an increase in the 2004

average PSCR costs?

A. The incremental increase in firm load was determined by the Company from

the load previously served by the Ford Rawsonville and GM Pontiac

cogenerators, which resulted in an incremental firm load increase of

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approximately 168.8 GWh annually. Three hospitals shut down cogenerators

as well, with a combined incremental increase of another 29.1 GWh annual for

a total impact of 197.9 GWh annually.

Q. What method did the Company utilize to determine the increase in

average PSCR costs as a result of the incremental increase in firm load?

A. A proxy cost estimate was used to determine the PSCR cost increase resulting

from increases in SMC firm load. The impact on the PSCR customers was

estimated using the differential between the average cost to serve interruptible

customers of $21.56/MWh and the average adjusted PSCR cost of

$14.22/MWh. The differential cost was $7.34/MWh. Applying the differential

cost to the estimated increase in SMC and LCC firm load of 197.9 GWh

resulted in an increase in total PSCR costs of approximately $1,453,000. The

impact of the cost increase is accounted for in Mr. O’Neill’s determination of

recoverable PSCR expense.

Q. What was the Company's 2004 actual system generation compared to the

forecast amount of system generation?

A. Please refer to Exhibit No. A-2 (JHB-2) which shows the actual and forecasted

generation by plant. Of the actual energy produced, approximately 80% was

from coal, 18% from nuclear and 2% from natural gas and oil.

All of the coal plants achieved higher than forecasted generation. The oil and

natural gas fueled plants were below forecast. Fermi was within 1% of the

forecast. Overall the system generated 709 GWh more than the forecast.

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As shown on Exhibit No. A-3 (JHB-3) the total system capacity factor was

51.4% compared to a forecast of 49.4%.

Q. What were the Company's 2004 actual purchases of power and energy

transactions and were there any significant changes from the forecast?

A. Please refer to Exhibit No. A-4 (JHB-4), which summarizes the Company's

purchases of power and energy, both actual and forecasted.

The total purchases amount of 4,650 GWh was 1,566 GWh above the

forecast. The Company purchased a total of 2,632 GWh from external utilities

in 2004. This amount was 329 GWh up from forecast. Economic purchases

were made throughout 2004 to supplement Detroit Edison generation, to meet

peak demands and to meet NSO.

Purchases from PURPA Qualifying facilities amounted to 535 GWh in 2004,

which was 245 GWh below the forecasted amount due to one of the facilities

entering into bankruptcy and ceasing to operate.

Purchases of Energy Imbalance energy from alternative electric suppliers

(AES) amounted to 1,482 GWh. The purchase of the Energy Imbalance

energy is due to the AES’s over scheduling energy to supply their customers’

load. Detroit Edison is required to purchase this energy in accordance with its

FERC-approved Ancillary Service Tariff. The average purchase price for

energy imbalance was only $20.77/MWh versus the overall average cost of

purchased power of $36.98/MWh. No energy imbalance was forecasted

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because the Company was unable to reasonably predict the energy scheduling

actions of the AESs.

Q. What were Detroit Edison’s capacity purchases for the summer of 2004?

A. The Company purchased 1,505 MW of capacity for the summer of 2004

compared to a forecast of 1,483 MW as shown on Exhibit No. A-4 (JHB-4). All

of the summer capacity purchased was in the form of call options. The energy

associated with the summer capacity amounted to 28 GWh, 602 GWh below

the forecast amount of 630 GWh. The cooler summer and the increased

Electric Choice sales, which reduced bundled peak demands, were the primary

reasons for the reduction from the Company’s bundled forecast.

Q. Did the Company’s summer capacity purchases include capacity for

Electric Choice Operating Reserve?

A. Yes. The 1,505 MW of capacity included 74 MW to provide operating reserve

for Electric Choice. The average premium paid for the 1,505 MW of capacity

was $8,681/MW. The cost of the 74 MW for operating reserve for Electric

Choice was $642,000. I will discuss the revenues associated with the

provision of this service in accordance with the Company’s ancillary service

tariff later in my testimony.

Q. Did the Company purchase power with capacity charges for a period

greater than six months in 2004?

A. Yes. Consistent with the 2004 PSCR Plan and many prior years, in 2004 the

Company purchased capacity and energy for greater than six months from

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several PURPA and P.A.2 cogeneration facilities and qualified small power

producers during the year.

Q. Did the Company incur any expenses associated with Financial

Transmission Rights (FTR) or redispatch/congestion cost in 2004?

A. No. The FTR and redispatch/congestion costs are expenses that won’t be

incurred until the Midwest Independent System Operator (“MISO”) energy

market begins operation. The MISO energy market did not begin operation in

2004 but is expected to begin operation on April 1, 2005.

Q. Did the Company reserve firm transmission service for the delivery of the

power it purchased during 2004?

A. Yes. The Company requested and confirmed, either seasonally or monthly as

available, firm point to point transmission service for its summer capacity

purchases. In addition, the Company also purchased point-to-point

transmission for deliveries and sales of purchased power energy from and to

non-MISO companies.

Q. What were the Company's 2004 third party wholesale power sales?

A. Please refer to Exhibit No. A-5 (JHB-5), which summarizes the Company's

2004 third party wholesale power sales, both actual and forecasted. As

shown, the Company was able to make significantly more sales than was

forecasted. This was due, in part, to the generation capacity available above

that required to serve Detroit Edison’s bundled load and the higher than

expected market prices. The average 2004 Cinergy day ahead market prices

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were $43.16/MWh on-peak and $24.49/MWh off-peak.

The Company made annual sales of 151 MW on-peak and 100 MW off-peak.

The Company also made additional non-summer monthly/seasonal on-peak

sales in the range of 300 MW to 1,100 MW.

Q. What was the network transmission expense for 2004?

A. Please refer to Exhibit No. A-6 (JHB-6), which is a summary of the network

transmission expense incurred to serve the bundled (non-Electric Choice) load.

Both the actual and forecasted expenses are shown for the year and for the

period of November 24, 2004 through December 31, 2004. In the Final Order

dated November 23, 2004 in MPSC Case No. U-13808, the MPSC authorized

the Company to include this network transmission expense as a PSCR

expense. Edison witness Mr. Kevin O’Neill develops the appropriate

jurisdictional factor for this expense and addresses its recovery through the

PSCR process.

Q. What is network transmission Schedule 1 expense?

A. Schedule 1 is the ancillary service for scheduling, system control and dispatch

service provided by the transmission provider. This service is required to

schedule the movement of power through, out of, within or into a control area

and must be purchased by the transmission customer (i.e. Detroit Edison) from

the transmission provider (i.e. International Transmission Company and

MISO). The monthly charge for Schedule 1 is the peak demand multiplied by

the FERC approved rate, currently $57.4741/MW-Month.

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Q. What is network transmission Schedule 9 expense?

A. Schedule 9 is the expense associated with network integration transmission

service. Each transmission customer taking network service, such as Detroit

Edison, pays the firm monthly zonal rate for the zone based upon where the

load is physically located. The Company (and its load) is located in zone 7:

International Transmission Company. The 2004 rate for zone 7 was

$1,075/MW-month.

Q. What is MISO Schedule 10 expense?

A. MISO Schedule 10 is the cost recovery adder under which MISO recovers its

cost of operation. The charge is based on the product of monthly peak demand

multiplied by the hours in the month multiplied by the approved rate. The

currently authorized maximum rate level is $0.15/MWh.

Q. What is encompassed in the FERC Transmission expense?

A. The FERC transmission expense is an adder charged by FERC to MISO and

is used to recover the operating costs for FERC itself. MISO in turn allocates

this cost to all MISO transmission customers, including those taking network

transmission service, like the Company. The 2004 rate charged by MISO to its

customers is $0.0419/MWh. The expense is determined by applying this rate

to the monthly peak demand multiplied by the hours in the month.

Q. What is MISO Schedule 18 Expense?

A. Schedule 18 represents a sub-regional rate adjustment established as a result

of a FERC settlement proceeding. In that proceeding it was determined that

JHB - 19

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short-term payments (ending September 30, 2005) would be made to the

GridAmerica transmission companies (First Energy, Northern Indiana Public

Service (NIPS), and Ameren) once they became part of the MISO. As a result

of achieving the settlement, the Company was able to reduce its exposure to a

much larger liability for itself and its customers.

Detroit Edison’s obligation under this settlement was to pay $75,000 per month

starting on October 1, 2003 when First Energy and NIPS joined MISO. The

payment amount increased to $83,333 per month starting May 1, 2004 when

Ameren joined MISO.

Q. Was the PSCR network transmission expense and MISO expense

reflective of the Company’s efforts to keep transmission costs as low as

possible?

A. Yes. The PSCR transmission expense that the Company incurred in 2004

consisted entirely of charges paid for network transmission which was provided

by ITC in accordance with its FERC approved rates and MISO in accordance

with its FERC approved rates. Detroit Edison has intervened in and continues

to participate in rate proceedings before FERC which could impact

transmission expense in an effort to keep rates as low as possible.

Q. What is the purpose of Exhibit No. A-7 (JHB-7)?

A. The purpose of Exhibit No. A-7 (JHB-7) is to develop the Stranded Cost Credit

from Third Party Wholesale Power Sales Net Proceeds for Detroit Edison’s

production fixed cost stranded costs reconciliation as discussed by Mr. Harvill.

JHB - 20

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Also developed is the PSCR Fuel and Net Proceeds Credit from Third Party

Wholesale Power Sales.

Q. What are third party wholesale power sales?

A. Third party wholesale power sales are the physical wholesale electric sales

made by the Company to other utilities and wholesale marketers under FERC-

approved tariffs. These are wholesale sales the Company made in addition to

retail bundled sales and wholesale full requirements customer sales.

Q. What are the gross proceeds from third party sales?

Under the Commission’s methodology, adopted in Case U-12639, the gross

proceeds from a third party wholesale power sale is the difference between the

price of the sale and the system average gross power supply cost. (December

20, 2001 Order in MPSC Case No. U-12639, p. 10, accepting Staff

methodology and MPSC Case No. U-12639, Tr. 467-468) The gross average

power supply cost is calculated as the sum of the generation expense plus the

purchased power expense divided by the sum of the generated energy plus

the purchased power energy.

Q. Have you excluded Energy Imbalance transactions from Third Party

Wholesale Power Sales for the gross proceeds calculation?

A. Yes. Consistent with the methodology used to determine net stranded costs in

MPSC Case No. U-13808, only direct third party wholesale power sales should

be included as an offset to the production fixed costs of the Company’s

generating units. Energy imbalance sales made under the Company’s FERC-

JHB - 21

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approved Ancillary Service Tariff were excluded from third party wholesale

power sales revenue. These sales were not made as a result of generation

that was freed up by customers that migrated to Electric Choice.

Energy imbalance is a transmission ancillary service that the Company

purchases and sells to its transmission provider and alternative electric

suppliers participating in Electric Choice. The energy imbalance is the

difference between actual load (or generation) and the scheduled load (or

generation). The Company purchases or sells energy imbalance under the

terms of the FERC transmission tariff. The Company has no control over these

transactions and does not and cannot schedule energy imbalance as a third

party wholesale power sale. Obviously, an energy imbalance sale to provide

energy to an alternative electric supplier is not made from resources “freed-up”

due to Electric Choice because these resources are serving Electric Choice

load. Therefore, again, energy imbalance transactions must be adjusted out of

account 447 in order to provide an accurate picture of third party wholesale

power sales.

Q: If the Company’s third party wholesale power sales do not include

energy imbalance sales, how should the gross revenue from energy

imbalance sales be treated?

A: I believe that the gross revenue, total revenue less fuel cost credited to PSCR,

should be treated as “Miscellaneous Revenue” similar to all other revenue from

the Company’s ancillary service tariff. These revenues are reported in the

FERC Form 1 and MPSC Form P-521, on page 331B, Other Electric

JHB - 22

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Revenues, Transmission Services. In Edison’s main rate case, Case No. U-

13808, all other revenues from the Company’s ancillary service tariff were

included in Total Revenues, line 1, as “Miscellaneous Revenues”, (reference

Exhibit No. A-15, Schedule C-1), and therefore have already been credited to

base rates.

Q. Have you calculated the third party gross proceeds for the year 2004?

A. Yes. The third party wholesale power sales gross proceeds is $126,884,000 as

shown on Exhibit No. A-7 (JHB-7). This is the difference between the third

party wholesale power sales revenue and the average fuel cost incurred to

make the sales based on the gross power supply cost. This methodology is

consistent with the previously approved Commission methodology. (November

23, 2004 Order in MPSC Case No. U-13808, pp. 90-97).

The calculation of third party wholesale power sales gross proceeds excludes

any recognition of production operation and maintenance (“O&M”) expenses.

Q. Have you calculated the production O&M expense to be recovered from

the third party wholesale power sales gross proceeds?

A Yes. The average production O&M cost for 2004 was $12.09/MWh based

upon the Company’s total Production O&M expense, including indirects, of

$585 million, and the Company’s total generation of 48,420 GWh. Applying

this average expense to the third party wholesale power sales of 6,084 GWh

results in a production O&M expense $73.556 million associated with the third

party wholesale power sales.

JHB - 23

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Q. Can you describe the calculation of the Third Party Wholesale Power

Sales Net Proceeds?

A Yes. The third party wholesale power sales net proceeds is calculated by

reducing the third party wholesale gross proceeds by the expense associated

with the production O&M for the subject third party wholesale power sales.

Q. How is the PSCR net proceeds credit from third party wholesale power

sales developed?

A The PSCR credit from third party power sales is a direct allocation of the third

party wholesale power sales net proceeds to PSCR in accordance with the

testimony of Company witness Terry S. Harvill. Mr. Harvill recommends that

76% of the net proceeds associated with third party wholesale power sales be

allocated to PSCR customers. This allocation is based upon the contribution

to 2004 Production Fixed Costs made by ultimate (a/k/a “bundled” or “full

service”) customers, and results in a credit to PSCR expense of $40.369

million.

Q. How is the PSCR Fuel and Net Proceeds Credit from Third Party

Wholesale Power Sales developed?

A The PSCR Fuel and Net Proceeds Credit from third party wholesale power

sales is developed by adding the fuel cost for Third Party Wholesale Power

Sales, the fuel cost for Energy Imbalance, and the PSCR Credit from Third

Party Wholesale Power Sales. This credit amounts to $135.418 million.

JHB - 24

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Q. How is the Stranded Cost credit from third party wholesale power sales

developed?

A The stranded cost credit from third party wholesale power sales is the balance

of third party wholesale power sales net proceeds after the PSCR credit. This

credit amounts to $12.960 million and is used by Mr. Sadagopan to reduce

production fixed cost stranded costs.

Q. Was the system operated in a reasonable and prudent manner during

2004?

A Yes, the system was operated in a reasonable and prudent manner. The NSO

unit cost of the Company’s resources was $14.22/MWh and was $1.31/MWh

below both the 2004 PSCR Plan forecast and $0.67/MWh below the 2003

actual costs. The Company made over 6,000 GWh of third party wholesale

power sales. The NSO unit cost only reflects a portion of the gross proceeds,

as described previously from those third party wholesale sales.

The cost to the industrial interruptible customers of $21.56/MWh was below

the 2003 cost of $24.13/MWh and below the 2004 PSCR Plan forecast of

$28.18/MWh. During the summer of 2004, the industrial interruptible

customers were not required to curtail their interruptible load.

The Company reliably served its customers by acquiring and utilizing a

summer purchase power portfolio at a reasonable cost. This is evidenced by

the fact that no firm customers were interrupted in 2004 and the ultimate cost

of the overall portfolio was well below the actual market price.

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Q. Does this conclude your testimony?

A. Yes.

JHB - 26




EXHIBITS

OF

JAMES H. BYRON

Michigan Public Service Commission Case No.: U-_______The Detroit Edison Company Exhibit No.: A-1 (JHB-1)2004 System Operation Summary Page: 1 of 1

Witness: J. H. Byron,S.M.Digaetano

( a ) ( b ) ( c ) ( d )

Line No. 2004 Actual

U-13808 2004 Plan 2004 Variance

12 Generation & Fuel3 - GWh 48,420 47,711 709 4 - $1,000 618,421$ 612,089$ 6,332$ 5 - $/MWh 12.77$ 12.83$ (0.06)$ 67 Ludington Losses8 - GWH (548) (484) (64) 9

10 Emission Allowance11 NOx - $1,000 1,250$ 1,759$ (509) 1213 Purchased Power14 - GWh 4,650 3,084 1,566 15 - $1,000 171,956$ 167,207$ 4,749 1617 PSCR Fuel & Net Proceeds Credit from Third Party Sales18 - GWh 6,372 1,846 4,526 19 - $1,000 135,418$ 28,385$ 107,033$ 2021 Network Transmission22 Annual - $1,000 99,430$ 128,914$ (29,484)$ 23 November 24-December 31 - $1,000 10,009$ 11,055$ (1,046)$ 2425 Net System Output : Annual Network26 - GWh 46,150 48,465 (2,315) 27 - $1,000 755,639$ 881,584$ (125,945)$ 28 - $/MWh 16.37$ 18.19$ (1.82)$ 29 Excluding Transmission -$/MWh 14.22$ 15.53$ (1.31)$ 3031 Net System Output : Nov 24- Dec 31 Network32 - GWh 46,150 48,465 (2,315) 33 - $1,000 666,218$ 763,725$ (97,507) 34 - $/MWh 14.44$ 15.76$ (1.32)$ 35 Excluding Transmission -$/MWh 14.22$ 15.53$ (1.31)$ 3637 R-10 Adjustment38 - GWh 1,308 1,408 (100) 39 - $1,000 28,207$ 39,678$ (11,471)$ 40 - $/MWh 21.56$ 28.18$ (6.62)$ 41 - Network Transmission Adj.$1,000 403$ -$ 403$ 4243 Net System Output Adjusted for R-10, SMC, LCC44 - GWh 44,842 47,057 (2,215) 45 - $1,000 637,608$ 724,047$ (86,439)$ 46 - $/MWh 14.22$ 15.39$ (1.17)$ 47484950

51 (1) Adjusted To not include SO2

(1)

Michigan Public Service Commission Case No.: U-_______The Detroit Edison Company Exhibit A-2 (JHB-2)2004 Electric Generation By Plant Witness: J. H. Byron,

Page: 1 of 1

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Line No. Plant

Primary Fuel Type

Actual Generation

U-13808 Plan

Generation2004

Variance (GWh) (GWh) (GWh)

12 Belle River Coal 7,534 7,204 33034 Conners Creek Gas 29 22 756 Fermi Nuclear 8,440 8,526 (86)78 Greenwood Gas/Oil 448 836 (388)9

10 Harbor Beach Coal 225 225 01112 Marysville Coal - - 1314 Monroe Coal 16,621 16,476 1451516 River Rouge Coal 3,347 2,764 5831718 St. Clair Coal 7,388 7,274 1141920 Trenton Channel Coal 4,333 3,968 3652122 Peakers Gas/Oil 83 416 (333)2324 Ludington Generation 1,427 1,139 28825 Pumping (1,975) (1,623) (352)26 Net (548) (484) (64)2728 Total System 47,900 47,227 673

Michigan Public Service Commission Case No.: U-_______The Detroit Edison Company Exhibit A-3 (JHB-3)2004 Capacity Factor Summary Witness: J. H. Byron,

Page: 1 of 1

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Line No. Plant

Net Demonstrated Operating Capability (Winter)

2004 Actual Capacity Factor

U-13808 Plan Capacity Factor

(MW) (%) (%)1

2 Belle River 1(1) 509 81.9 83.13 Belle River 2(1) 517 83.8 76.845 Conners Creek 215 1.6 1.267 Fermi 1131 85.0 89.189 Greenwood 785 6.5 12.11011 Harbor Beach 103 24.9 24.91213 Marysville 84 0.0 0.01415 Monroe 1 770 63.1 65.516 Monroe 2 750 62.9 65.817 Monroe 3 795 44.4 50.018 Monroe 4 775 75.6 64.11920 River Rouge 2 247 75.2 63.821 River Rouge 3 280 69.7 56.12223 St. Clair 1 153 59.7 49.324 St. Clair 2 162 58.1 47.125 St. Clair 3 171 40.0 40.926 St. Clair 4 158 44.2 39.927 St. Clair 6 321 67.3 66.128 St. Clair 7 450 67.6 71.12930 Trenton Channel H.P. 210 66.7 48.131 Trenton Channel 9 520 67.9 68.13233 Peakers 1371 0.2 3.53435 Ludington 917 17.7 14.13637 Total System 11394 51.4 49.4383940 (1) Detroit Edison Ownership Portion

Michigan Public Service Commission Case No.: U-_______The Detroit Edison Company Exhibit No.: A-4 (JHB-4)2004 Purchases of Power and Energy Summary Witness: J. H. Byron

Page: 1 of 1

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Line No. Purchases Actual 2004

2004 U-13808 Plan Variance

12 Wholesale3 - GWh 2,605 1,674 931 4 - $1,000 95,092$ 62,067$ 33,025 56 Energy Imbalance7 - GWh 1,482 1,482 8 - $1,000 30,791$ 30,791 910 Summer Contracts (5x16)11 - MW 0 400 (400) 12 - GWh - 416 (416) 13 - $1,000 -$ 21,594$ (21,594)$ 1415 Summer Calls16 - MW 1,505 1,083 422 17 - GWh 28 214 (186) 18 Energy - $1,000 3,152$ 12,610$ (9,458)$ 19 Premium - $1,000 13,333$ 17,152$ (3,819)$ 2021 Transmission22 - $1,000 1,786$ 9,151$ (7,365)$ 2324 External FTR25 - $1,000 -$ 3,273$ (3,273)$ 2627 Redispatch/Congestion Cost28 - $1,000 -$ 800$ (800)$ 2930 PURPA Qualifying Facilities31 - GWh 535 780 (245) 32 - $1,000 27,802$ 40,560$ (12,758)$ 3334 Total Purchases35 - GWh 4,650 3,084 1,566 36 - $1,000 171,956$ 167,207$ 4,749$

Michigan Public Service Commission Case No.: U-_______The Detroit Edison Company Exhibit No.: A-5 (JHB-5)2004 Summary of Third Party Wholesale Power Sales Witness: J. H. Byron

Page: 1 of 1

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Line No. Sales 2004 Actual

2004 U-13808

Plan Variance12 Wholesale3 - GWh 6,084 1,846 4,2384 - $1,000 217,637$ $57,768 159,869$ 56 Energy Imbalance7 - GWh 288 2888 - $1,000 26,569$ -$ 26,569$ 9

10 Total Sales11 - GWh 6,372 1,846 4,52612 - $1,000 $244,206 57,768 186,438$

Michigan Public Service Commission Case No.: U-_______The Detroit Edison Company Exhibit No.: A-6 (JHB-6)2004 Summary of Network Transmission Expense Witness: J. H. Byron

Page: 1 of 1

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Line No. 2004 Actual

2004 U-13808 Plan

November 24 - December 31 2004 Actual

November 24 - December 31

2004 U-13808 Plan Variance

12 Network Transmission3 Schedule 1 - $1,000 $4,468 $5,606 $450 $475 -$254 Schedule 9 - $1,000 $82,994 $105,389 $8,428 $8,929 -$50156 MISO Schedule 107 - $1,000 $8,807 $10,771 $905 $922 -$1789 MISO Schedule 1610 - $1,000 $0 $1,857 $186 -$1861112 MISO Schedule 1713 - $1,000 $0 $2,525 $0 $306 -$3061415 FERC Transmission 16 - $1,000 $1,624 $2,765 $123 $237 -$1141718 SECA Transmission19 - $1,000 $0 $0 $0 $02021 Schedule 1822 - $1,000 $1,538 $0 $103 $0 $1032324 Total Bundled Transmission 25 - $1,000 $99,430 $128,914 $10,009 $11,055 ($1,046)

Michigan Public Service Commission Case No.: U-_______The Detroit Edison Company Exhibit No.: A-7 (JHB-7)2004 Third Party Wholesale Power Sales Net Proceeds Witness: J. H. Byron

Page: 1 of 1

( a ) ( b )

Line No. Item Actual 200412 Generation & Fuel3 - GWh 48,420 4 - $1,000 618,421$ 56 Emission Allowance7 NOx - $1,000 1,250$ 89 Purchased Power

10 - GWh 4,650 11 - $1,000 171,956$ 1213 Gross Power Supply14 - GWh 53,070 15 - $1,000 791,627$ 16 - $/MWh 14.92$ 1718 Third Party Wholesale Power Sales 19 - GWh 6,08420 - $1,000 $217,6372122 Fuel Cost of Third Party Wholesale Power23 Sales Based on Gross Power Supply24 - $1,000 90,753$ 2526 Third Party Gross Proceeds 126,884$ 2728 Production O&M for Third Party29 Wholesale Power Sales 30 - GWh 6,084 31 - $1,000 73,556$ 32 - $/MWh 12.09$ 3334 Third Party Wholesale Power Sales35 Net Proceeds36 - $1,000 53,328$ 3738 PSCR Net Proceeds Credit from Third39 Party Wholesale Power Sales (80%)40 - $1,000 40,369$ 4142 Fuel Cost of Energy Imbalance Based on43 Gross Power Supply44 Energy - GWh 288 45 Fuel Cost - $1,000 4,296$ 4647 PSCR Fuel & Net Proceeds Credit from48 Third Party Wholesale Power Sales @ 76%49 - $1,000 135,418$ 5051 Stranded Cost Credit from Third Party52 Wholesale Power Sales Net Proceeds @ 24%53 - $1,000 12,960$




QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

JOHN C. DAU

THE DETROIT EDISON COMPANY QUALIFICATIONS OF JOHN C. DAU

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A. My name is John C. Dau. My business address is The Detroit Edison

Company, Belle River Power Plant, 4505 King Road, China Township

Michigan, 48054.

Q. Please state your educational background.

A. I received a Bachelor of Science Degree in Mechanical Engineering in 1982

from the University of Michigan and a Master of Science in Mechanical

Engineering in 1985 from the University of Michigan.

Q. Are you a Registered Professional Engineer?

A. Yes. I am registered as a Professional Engineer by examination in the State of

Michigan.

Q. Have you had a role in any prior rate proceedings before the Michigan

Public Service Commission?

A. Yes. While employed in the Fuel Supply Department, I assisted in the

preparation of testimony, exhibits, workpapers and discovery responses in

support of the Company’s fossil fuel witness in various cases before the

Commission. I provided similar support for Mr. Guillaumin’s testimony

regarding fossil generation maintenance and outages over 90 days in duration

in the Company’s 1997 PSCR reconciliation, MPSC Case No. U-11175-R, and

in the Company’s 1998 PSCR reconciliation, MPSC Case No. U-11528-R. In

addition, I sponsored testimony on this subject in the 1999 PSCR

Reconciliation, MPSC Case No. U-11800-R.

JCD - 1

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Q. What is your present position with The Detroit Edison Company?

A. In September 2003 I was assigned the position of Production Manager, Belle

River Power Plant. I report directly to the Plant Director of the Belle River and

North Area Power Plants. My current responsibilities include the day-to-day

supervision of the operations group, which includes all the operating personnel

assigned to Belle River. Included in this responsibility is my participation in the

daily fossil generation conference calls which review the operating and

maintenance status of the Company’s power plants, including outage status.

Further, I also participate in monthly production manager meetings which

include a review of fuel supply, maintenance and operations at the Company’s

plants.

Q. Please describe your business experience.

A. Upon graduation from the University of Michigan in 1982, I began my career

with Detroit Edison and was assigned to Power Generation. Nearly all of my

23 years at Detroit Edison have been spent in engineering related areas

including Power Generation, Fuel Supply, and Business Planning. I have been

assigned to, or worked at, all of the fossil generating plants during this time.

From 1982 through 1988, I was involved in providing technical services,

consultation, and problem solving services in support of plant operations. This

was through assignments directly to a power plant as an engineer in the

maintenance or technical area or in a central staff position in the support group

of Production Services. My role in the Production Services group was that of a

Fuel and Environmental Engineer with responsibilities for several power plants.

JCD - 2

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The function of the group was to ensure that all environmental regulations

were understood and followed and to provide technical expertise in handling

and burning fossil fuels.

In 1988, I was assigned to the Fuel Supply department where I was

responsible for the procurement of coal and the related transportation. This

included the administration of several coal supply and transportation contracts.

Additionally, I was responsible for providing the all of the fossil fired power

plants with technical services related to fuel.

In 1994, I began a one-year assignment as the Supervisor of the Unit Train

group of Fuel Supply, responsible for the day-to-day maintenance and

operation of the unit train fleet.

I spent the next year as an analyst in the Business Planning group of Power

Supply. This position focused on corporate performance measures. From

October 1996 until March 1998 I was assigned to the River Rouge Power

Plant, first as Business Superintendent and then with the combined roles of

Business and Reliability Superintendent. In this capacity I was responsible for

the business functions of the plant and the day-to-day technical and

maintenance functions, including instrumentation.

In March 1998, I was assigned as Project Manager for the restart of the

Conners Creek Power Plant, a coal fired plant which had been placed in

economy reserve in 1988. This position had responsibility for the restart

JCD - 3

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project as well as the initial operational testing of the plant.

In September 1998, I was assigned to the position of Supervisor – Reliability

Strategies, Asset Management Organization. While in this position I had

administrative responsibilities for all of the technical personnel assigned to the

Company’s fossil fueled power plants. Due to a reorganization of the Asset

Management Group in 2001, I was assigned to the position of Supervisor –

Labor Utilization, Asset Management. This position had responsibility for the

mobile labor force for all of Fossil Generation.

In September 2003, I began my current assignment as Production Manager,

Belle River Power Plant.

JCD - 4

THE DETROIT EDISON COMPANY DIRECT TESTIMONY OF JOHN C. DAU

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A. The purpose of my testimony is to explain the 2004 actual periodic

maintenance at Detroit Edison’s power plants and to discuss the differences

from the 2004 planned maintenance schedule.



Exhibit No. A-8 (JCD-1) 2004 Detroit Edison Periodic Outage Plan

Exhibit No. A-9 (JCD-2) Actual Detroit Edison 2004 Periodic Outages

Q. How was the 2004 Detroit Edison periodic outage plan developed?

A. A determination of the required and/or desired 2004 maintenance for each

generating unit was made using the Company’s 10 year, long-range forecast

and the previous two years’ actual maintenance. Based on this information, a

preliminary plan is prepared by Generation Optimization for the spring and fall

maintenance periods and reviewed with the plants to insure adequate

resources are available. The maintenance budget is then prepared from the

preliminary periodic outage plan.

To establish the most economic schedule based upon system constraints, a

production costing simulation is performed and the Maintenance Scheduler

Model is run to determine the most economic plan. This revised plan is again

reviewed by each plant and approved or modified as necessary. The plan is

then presented to the staff of Fossil Generation for final approval. It should be

noted that this revised plan might be further modified as necessary to

JCD - 5

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accommodate changes in system operation.

Q. Can you explain Exhibit No. A-8 (JCD-1).

A. Exhibit No. A-8 (JCD-1) is the 2004 Detroit Edison periodic outage plan.

Shown on Exhibit No. A-8 (JCD-1) is the planned or scheduled maintenance

cycle for each generating unit and its capacity impact.

Q. Can you explain Exhibit No. A-9 (JCD-2).

A. Exhibit No. A-9 (JCD-2) is the Actual Detroit Edison 2004 Periodic Outages.

The information shown on Exhibit No. A-9 (JCD-2) is in a similar format to that

shown on Exhibit No. A-8 (JCD-1).

Q. Mr. Dau, based on the 2004 actual maintenance shown on Exhibit No. A-9

(JCD-2), are there any differences from the 2004 periodic outage plan

shown on Exhibit No. A-8 (JCD-1)?

A. In general, the 2004 Periodic Outage Plan was followed. All work scheduled

during the outages on Monroe Units 1 and 3, St. Clair Units 3 and 4, and

Harbor Beach was completed, assuring continued availability of these

generating resources to serve Detroit Edison customers. However, there were

some differences, specifically:

• Monroe Unit 1 – main unit transformer outage. This outage, which began

on December 23, 2003, proactively replaced the transformer, which had

reached end of life, with the system spare. This was completed on

January 24, 2004. An additional outage of three weeks duration in June

was taken to replace the system spare with the new main unit

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transformer.

• Greenwood Unit 1 – this outage was modified from 9 weeks to 2 weeks.

The majority of the work was deferred to 2005.

• Throughout the schedule there were a number of short duration outages

planned for furnace cleaning which were not taken because conditions

simply did not warrant the outage.

Q. Were there any outages on a Fossil Steam Generation unit that exceeded

90 days?

A. Yes, Monroe Unit 3 and St. Clair Unit 3.

Q. Were any of these outages scheduled for more than 90 days?

A. No.

Q. Why did the Monroe Unit 3 outage extend past 90 days?

A. The outage extended from a scheduled 84 days to an actual 119 days. The

added 35 days was due primarily to complications encountered during the

planned installation of new turbine components. Unanticipated failure of other

turbine related components during unit startup activities accounted for the

balance of the increased outage duration.

Q. Why were the turbine components replaced?

A. The replacement of the original turbines, which were approximately 30 years

old, was economically justified. The new components incorporate a “dense

pack” steam path design that allows the unit to function at a higher efficiency

JCD - 7

J.C. DAU Line No.

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than the original design. In addition, there is increased capability with the

same steam flow. The new net demonstrated capacity of the redesigned

turbine is 795 MW, an increase of 45 MW from its previous net demonstrated

capacity. Thus, Detroit Edison customers are provided additional capacity for

the same fuel expenditures.

Q. Did other units at Monroe have this work performed?

A. No. Monroe Units 1 and 4, which are both General Electric turbines, had their

high pressure turbines replaced with higher efficiency components in 2002 and

2003, respectively. The work performed on Monroe Unit 3, a Siemens-

Westinghouse unit, was Detroit Edison’s first experience at replacing both the

high pressure and low pressure turbines, as well as its first dense-pack turbine

installation on a Siemens-Westinghouse unit. The Company’s original

estimate of the time required to complete all of the associated work proved to

be somewhat optimistic.

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More specifically, the iterative process of aligning and balancing the new LP

turbine simply took more effort than projected. Monroe Unit 2, also a Siemens-

Westinghouse design, will receive the same upgrade as Unit 3 in 2005 and

lessons learned from this outage have been incorporated in that plan.

Q. Why did the St. Clair Unit 3 outage extend past 90 days?

A. The St. Clair Unit 3 outage was originally scheduled for 87 days. The actual

duration of the outage was 94 days, an extension of 7 days. This extension

was due to a 15 day extension of the generator rewind project. The generator

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rewind was performed by a vendor, working 24/7, at their facility. The primary

cause of the delay was that the vendor had to perform some unanticipated

work on the annealing coils after they arrived on site. This work had to be

completed prior to completion of the rewind.

Additionally, the vendor underestimated the time it took to tape the end turns.

The delay was reduced from 15 days to 7 days due to Detroit Edison’s

rearrangement of the final maintenance activities and pro-active check out

procedures.

Q Mr. Dau, based on the 2004 actual maintenance shown on Exhibit No. A-9

(JCD-2), are there any differences from the 2004 Periodic Outage Plan

shown on Exhibit No. A-8 (JCD-1) pertaining to the Ludington Pumped

Storage Facility?

A. There were two changes to the planned Ludington outages in 2004. The

Ludington 3 outage was increased from five weeks to eight weeks to replace

the thrust shoes. The Ludington 5 outage was increased to 69 days due to the

thrust bearing failing in service versus being taken out of service in a controlled

fashion.

Q. Is Detroit Edison responsible for maintaining the pumped storage units

at Ludington?

A. No, the Ludington units are maintained by Consumers Energy Company.

Detroit Edison monitors the maintenance progress and is kept informed of all

work performed at Ludington through bimonthly and quarterly meetings.

JCD - 9

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Q. Were any of the outages that lasted longer than 90 days caused or

extended by the actions of Detroit Edison?

A. No. Detroit Edison did not cause the outages to exceed 90 days nor could the

outages have been reasonably made to be shorter in duration.


A. Yes.

JCD - 10




EXHIBITS

OF

JOHN C. DAU

5 12 19 26 2 9 16 23 1 8 15 22 29 5 12 19 26 3 10 17 24 31 7 14 21 28 5 12 19 26 2 9 16 23 30 6 13 20 27 4 11 18 25 1 8 15 22 29 6

JAN FEB MAR APR MAY JUN JULY AUG SEP OCT NOV DEC5 12 19 26 2 9 16 23 1 8 15 22 29 5 12 19 26 3 10 17 24 31 7 14 21 28 5 12 19 26 2 9 16 23 30 6 13 20 27 4 11 18 25 1 8 15 22 29 6 13 20 27

DETROIT

Prepared By:_____________L. FLOYDAppproved On: _______

2004 Periodic Factor:______Without Fermi:________

Approved By:_______________

Power Plant LegendBH-Beacon Htg LUD-LudingtonBR-Belle River MO-MonroeF2-Fermi 2 MV-MarysvilleGW-Greenwood RR-River RougeHB-Harbor Beach SC-St Clair

TC-Trenton Ch

Outage LegendAH-Air HeaterBA&I-Boiler Annual & InspBFP-Boiler Feed PumpBI-Boiler InspectionBORE-Boresonic InspCC-Chemical CleaningCOND-Conderser cleaningDR-Duct Replacement

ECON-EconomizerFC-Furnace CleaningFWH-Feedwater HeaterGRR-Gen Retain RingsGEN-GeneratorH-HydroHP-High PressureHRH-Hot Reheat

INS- InsuranceINSP-InspectionIP-Intermediate PressureLP-Low PressureLST-Lower Slope TubesMTG-Main TurbgeneratorOH-OverhaulREFL-Refuel( Nuclear)

REPL-ReplacementsRET-Retaining RingsREWD-RewindSTK-StackSUPHT-SuperheaterTO-Turb OverhaulTUR-TurbineWK-Weeks

JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC13 20 27

/4/20/04

MON-3

2004 MAJOR MAINTENANCE SCENARIO

RF-10

1131MW 30DA

LUALL

LU-3

153MW 5WK

SC-4

158MW 12WK

BR

FC

1

168MW 12.5WK

SC-3

LU-5

153MW 9WK

MO-1

RR-3

3WK

GW-1

785MW9WK

BR

FC

1BR

FC

2BR

FC

2BR

FC

2BR

FC

1BR

FC

1

SC

FC

6

EDISONFOSSIL GENERATION

TC9 80mw TC9 80mw

SC7 70mw SC7 70mw

2/08/04S/ DBH,NAB

TC-7A

3WK

750MW 12WK

RR-2

2WK

TC9 80mw

SC

1

SC

2

MO-1

3WK

MO

2

LU-2

3WK

SC

FC

4

SC

FC

7BR

FC

2HB1

2WK

MO3

MPSC Case No.: U-_______Exhibit No.: A-8 (JCD-1)Page: 1 of 1Witness: J.C. Dau

MPSC Case No.: U-_______Exhibit No. A-9 (JCD-2)Page: 1 of 1Witness: J.C. Dau

2004 Actual Maintenance (P3M)Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Week Starting 4 11 18 25 1 8 15 22 29 7 14 21 28 4 11 18 25 2 9 16 23 30 6 13 20 27 4 11 18 25 1 8 15 22 29 5 12 19 26 3 10 17 24 31 7 14 21 28 5 12 19 26

Belle River 1 FC2 Wk

Exciter

Belle River 2 FC FC

Connors Creek

Greenwood2 Wk Blr Overhaul

Harbor Beach3 Wks Blr Overhaul

Monroe 15 Wk Mn Transf Grd Elec Comp

3 week Main Trans

10 day BSVs

Monroe 22 Wk

Blr OH

Monroe 3 12 Week Periodic - Boiler Misc5 Week Periodic

Extension

Monroe 4

River Rouge 22 Wk

Blr Insp

River Rouge 3Blr Insp &

Bnkr Repair

St. Clair 1Blr

Tube

St. Clair 2Blr

Tube

St. Clair 3 14 Week Periodic - Major Boiler Overhaul

St. Clair 4Blr Tube Cleaning 12 Week Periodic - Major Boiler Overhaul

St. Clair 6 FC

St. Clair 7Blr Tube Cleaning

Trenton 7Trb Cnt

VlvsTurbine Control

ValvesTube Leaks

Trenton 8Crc Wtr

VlvsTube Leaks

HP FW Htr

Trenton 9RH Stp

Vlvs

Ludington102 MW Lud #4 1/5/04-1/18/04

102 MW Lud #5 1/12/04-3/15/04102 MW Lud #2 102 MW Lud #3

Fermi 2Normal

Refueling

Note: Outages are shown for full weeks only, starting on Sundays.Typically the outage will start the Friday evening prior to the date shown. Approved Palmer

Date: 2/28/05

Updated by: Dianne Owen - Gen Ops




QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

STEVEN M. DIGAETANO

THE DETROIT EDISON COMPANY QUALIFICATIONS OF STEVEN M. DIGAETANO

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A. My name is Steven M. DiGaetano. My business address is The Detroit Edison

Company, 2000 Second Avenue, Detroit, Michigan 48226.

Q. What is your educational background?

A. In 1987, I received a Bachelor’s degree in Accounting from Michigan State

University.

Q. Are you a Certified Public Accountant?

A. Yes, I have qualified under the Michigan law regulating the practice of public

accountancy and I am licensed to use the title Certified Public Accountant

(CPA) in the State of Michigan.

Q. What is the nature of your accounting work experience?

A. I have seventeen years of experience including public and corporate

accounting. I have prepared financial statements, supporting schedules, and

narrative commentaries for internally and externally legal reporting entities. I

have managed several accounting projects including software implementation,

training, instituting accounting controls and development of databases. My

accounting experience includes an emphasis in reporting (internal and

external) and forecasting.

Q. Have you had any additional training that relates to accounting for

utilities?

A. Yes, I have taken the following courses that relate to accounting for utilities.

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• Fundamentals of Energy Derivatives and Competitive Markets

• Risk Management for Energy Companies

• Front to Back Office: Trading Controls and Best Practices

• Value – at – Risk: The Basics

• Utility Finance & Accounting for Financial Professionals

• FERC 101/102 – Fundamentals of Industry Restructuring and FERC

• Midwest Market Initiatives

Q. What is your work experience with Detroit Edison?

A. I started my career with Detroit Edison in September 1999, as a Financial

Consultant in the Controller’s Organization and was promoted to Senior

Financial Consultant in October 2000. My responsibilities included accounting

and forecasting for the balance sheet and income statement items associated

with power supply expenses. In March of 2003, I was promoted to Supervisor

Financial Management. My responsibilities include supervising the accounting,

reporting and forecasting of Detroit Edison’s revenues and power supply

expenses.

SMD - 2

THE DETROIT EDISON COMPANY DIRECT TESTIMONY OF STEVEN M. DIGAETANO

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A. The purpose of my testimony and supporting exhibits is to provide Detroit

Edison’ s booked cost of fuel consumed, NOX emission allowances consumed,

purchased power cost, cost of network transmission and third party wholesale

power sales revenue for the year ended December 31, 2004. The specific

accounts under the MPSC uniform system of accounts include:

• Account 555 Purchased Power Expense

• Account 565 Transmission Provided by Others

• Account 447 Sales for Resale (Third Party Wholesale Revenue only)

• Account 501 Fossil Fuel Expense - Steam

• Account 547 Fossil Fuel Expense - Other

• Account 518 Nuclear Fuel Expense

• Account 509 NOX Emission Allowances Expenses



Exhibit No. A-10 (SMD-1) Power Supply Costs other than Fuel

Exhibit No. A-11 (SMD-2) Total Electric Department Fuel Expense

Exhibit No. A-12 (SMD-3) Total Nuclear Fuel Expense

Exhibit No. A-13 (SMD-4) Transmission Expense by Month

Exhibit No. A-14 (SMD-5) Transmission Expense incurred after

November 23, 2004.

Q. Were these exhibits prepared by you or under your direction?

A. Yes they were.

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Q. Can you explain the costs that are portrayed on your exhibits?

A. Yes. I am sponsoring all of the booked costs that were included in the 45 Day

Reports which were filed with the Michigan Public Service Commission

(MPSC) for the 2004 calendar year reporting period. These costs included

fuel, purchased power, transmission and NOX emission allowances. In

addition, my exhibits present the third party wholesale power sales revenues

(Account 447).

These costs and revenues mentioned above were recorded in accordance with

the Commission’s Uniform System of Accounts.

Q. What is Detroit Edison's total booked cost of purchased power and

network transmission that should be reconciled for the year 2004?

A. The total booked cost in 2004 for purchased power and network transmission

as shown on Exhibit No. A-10 (SMD-1) was $171,956,207 and $9,595,421,

respectively.

Q. What is Detroit Edison’s total booked third party wholesale power sales

revenue?

A. The total booked third party wholesale power sales revenue in 2004, as shown

on Exhibit No. A-10 (SMD-1) was $244,205,931.

Q. Can you describe the MISO Schedule 7, 8, and 18 adjustments that you

made to the booked cost for Purchased Power, Account 555?

A. Yes. Adjustments were made to properly reflect these costs in the proper

SMD - 4


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recoverable accounts. Expense for MISO Schedules 7 and 8 (firm and non-

firm point-to-point transmission service, respectively) has been removed from

Account 565 and added to Account 555. MISO Schedule 18 (Sub-Regional

Rate Adjustment) transmission expense was removed from Account 555 and

added to Account 565. The treatment and recovery of MISO Schedule 18

expense is further discussed in the testimonies of Detroit Edison’s witnesses

Mr. Kevin L. O’Neill and Mr. James H. Byron. The adjustments reduced the

Company’s PSCR-recoverable purchased power expense for 2004.

Q Did you make any other adjustments to transmission expense, account

565?

A. Yes. In addition to the inclusion of expense associated with MISO Schedule

18 and the exclusion of expense associated with MISO Schedules 7 and 8, a

reduction in transmission expense of $1,467,546 was made to properly reflect

expense associated with MISO Schedules 2 (Reactive Supply and Voltage

Control from Generation Sources Service), 3 (Regulation and Frequency

Response Service), 5 (Spinning Reserve Service), and 6 (Supplemental

Reserve Service) as O&M expense. These costs were not identified as PSCR

expense pursuant to the Michigan Public Service Commission’s November 23,

2004 Order in MPSC Case No. U-13808.

Q. Can you describe the purpose of Exhibit No. A-13 (SMD-4) and Exhibit

No. A-14 (SMD-5)?

A. These exhibits are a summary of transmission expenses that are PSCR-

recoverable commencing with the MPSC Final Order in MPSC Case No. U-

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13808 dated November 23, 2004. As indicated on Exhibit No. A-13 (SMD-4),

the total gross booked transmission costs incurred by Detroit Edison in 2004

was $99,515,790. The total gross booked transmission costs incurred after

November 23 2004, as indicated on Exhibit No. A-14 (SMD-5) was

$10,009,221.

A further discussion of the regulatory treatment of these costs is included in

the testimony of Detroit Edison witness Mr. Kevin O’Neill.

Q. What was the nuclear fuel expense recorded in Account 518 for the year

ended December 31, 2004?

A. As shown on Exhibit No. A-12 (SMD-3), total nuclear fuel expense for the year

2004 was $35,701,100. The components of the expense consisted of front-end

amortization of $26,844,055 and regulatory costs of $8,857,045.

Q. Was the 2004 nuclear fuel expense summarized on Exhibit No. A-12

(SMD-3) calculated consistent with prior years?

A. Yes, with the exception of in-core interest charges (costs from nuclear fuel

leases). Currently, Detroit Edison owns the nuclear fuel so no interest

expense is being recognized as a PSCR fuel expense. However, Detroit

Edison does incur expense related to the financing costs of the fuel and that

expense is recovered through base rates.

Q. What are the components of fossil fuel expense?

A. Total fossil fuel expense, including NOX emission allowance expense, of

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$583,968,984 is shown on Exhibit No. A-11 (SMD-2) and includes

$532,860,252 of coal expense, $24,359,384 of oil expense, $25,499,792 of

natural gas expense and $1,249,556 of NOX emission allowance expense.

These amounts are recorded in Accounts 501 and 547 and are derived using

the Company’s Power Plant Performance Management System (P3M), which

calculates fuel inventories and consumption by type of fuel for each plant and

inventory site. P3M summaries are included in my workpapers.

Fossil fuel expense includes the cost of fuel, freight charges, Midwest Energy

Resources Company (MERC) operating expenses less MERC third party

revenues, reclamation fees, severance taxes, royalties and other fuel

payments. These costs are initially debited to Account 151 - Fuel Stock and

are subsequently charged to expense, as the fuel is consumed, based on an

average inventory cost method.

NOX allowance costs are initially debited to Account 158 and are subsequently

charged to expense Account 509, as the allowances are consumed, based on

an average inventory cost method. It should be noted that NOX emission

allowances are consumed from June through September. Adjustments were

made in October through December to true up actual usage.

Q. Does this complete your testimony?

A. Yes, it does.

SMD - 7




EXHIBITS

OF

STEVEN M. DIGAETANO

The Detroit Edison Company - SummaryPower Supply Costs Other Than FuelFor the year ended December 31, 2004

January February March April May JuneThird Party Wholesale Revenue

Account 4471 Month 22,206,217$ 18,561,632$ 20,936,961$ 14,997,712$ 9,278,730$ 15,337,717$

Year-to-Date 22,206,217$ 40,767,849$ 61,704,810$ 76,702,522$ 85,981,252$ 101,318,969$

Purchased PowerAccount 555

1 Month 14,750,222$ 12,656,132$ 13,973,318$ 10,269,382$ 13,193,556$ 18,268,058$ Add Schedule 7& 8 Adjustment 4,081 3,015 26,966 10,411 5,816 Less Schedule 18 MISO Adjustment - - - 88,460 49,116 49,116 Adjusted Purchase Power 14,754,303$ 12,656,132$ 13,976,333$ 10,207,888$ 13,154,851$ 18,224,757$

Year-to-Date 14,754,303$ 27,410,435$ 41,386,768$ 51,594,656$ 64,749,507$ 82,974,264$

PSCR Transmission Expense**Account 565

1 Month -$ -$ -$ -$ -$ -$ Less Schedule 7& 8 Adjustment - - - - - - Add Schedule 18 MISO Adjustment - - - - - - Adjusted Purchase Power $0 $0 $0 $0 $0 $0

Year-to-Date -$ -$ -$ -$ -$ -$

** Amount represents PSCR Transmission costs for the period November 24, 2004 through December 31, 2004.

MPSC Case No. U-_______Witness: S.M. DiGaetanoExhibit No. A-10 (SMD-1)

Page 1 of 2

The Detroit Edison Company - SummaryPower Supply Costs Other Than FuelFor the year ended December 31, 2004

July August September October November DecemberThird Party Wholesale Revenue

Account 4471 Month 19,521,303$ 18,881,359$ 19,687,773$ 28,628,844$ 19,776,617$ 36,391,066$

Year-to-Date 120,840,273$ 139,721,631$ 159,409,404$ 188,038,248$ 207,814,866$ 244,205,931$

Purchased PowerAccount 555

1 Month 15,913,738$ 19,472,888$ 16,320,023$ 10,116,860$ 9,781,238$ 17,636,552$ Add Schedule 7& 8 Adjustment 7,736 5,105 5,478 3,382 10,496 3,145 Less Schedule 18 MISO Adjustment 49,116 49,116 49,116 49,116 49,116 49,116 Adjusted Purchase Power 15,872,358$ 19,428,877$ 16,276,385$ 10,071,125$ 9,742,618$ 17,590,580$

Year-to-Date 98,846,622$ 118,275,499$ 134,551,883$ 144,623,009$ 154,365,626$ 171,956,207$

PSCR Transmission Expense**Account 565

1 Month -$ -$ -$ -$ 1,466,671$ 8,073,766$ Less Schedule 7& 8 Adjustment - - - - 2,449 3,145 Add Schedule 18 MISO Adjustment - - - - 11,461 49,116 Adjusted Purchase Power $0 $0 $0 $0 $1,475,683 $8,119,738

Year-to-Date -$ -$ -$ -$ 1,475,683$ 9,595,421$

** Amount represents PSCR Transmission costs for the period November 24, 2004 through December 31, 2004.


Page 2 of 2

The Detroit Edison CompanyTotal Electric Department Fuel ExpenseFor the year ended December 31, 2004

January February March April May June

Electric DepartmentFuel Consumed Expense * (Accounts 501, 509, 518 and 547)

Coal 45,125,364$ 44,136,837$ 44,045,436$ 34,964,495$ 34,842,203$ 41,994,401$

Oil 4,944,753 1,309,863 1,568,768 2,497,583 2,374,007 3,055,557

Gas 3,311,123 1,294,458 763,387 1,173,455 3,773,804 2,946,235

Total Fossil Fuel $53,381,240 $46,741,158 $46,377,591 $38,635,533 $40,990,014 $47,996,193

NOX Emission Allowance 267,490

Total Fossil Fuel with NOX Allowance 53,381,240 46,741,158 46,377,591 38,635,533 40,990,014 48,263,683

Nuclear 3,390,878 3,284,130 3,452,751 3,370,041 3,475,715 3,360,479

Total Fuel Expense 56,772,118$ 50,025,288$ 49,830,343$ 42,005,574$ 44,465,729$ 51,624,162$

* Expenses tie to Consolidated Income Statement (WP(JRK-1) pages 1 of 48 thru 12 of 48) and P3M (WP(JRK-1) pages 13 of 48 thru 48 of 48).


Page 1 of 2

The Detroit Edison CompanyTotal Electric Department Fuel ExpenseFor the year ended December 31, 2004

July August September October November December TotalElectric DepartmentFuel Consumed Expense * (Accounts 501, 509, 518 and 547)

Coal 48,042,612$ 47,569,813$ 46,652,003$ 45,482,423$ 48,710,325$ 51,294,339$ 532,860,252$

Oil 2,963,436 1,970,392 748,142 778,340 1,245,063 903,481 24,359,384

Gas 1,763,893 3,034,032 2,997,680 759,358 1,818,632 1,863,735 25,499,792

Total Fossil Fuel $52,769,941 $52,574,237 $50,397,825 $47,020,120 $51,774,021 $54,061,554 $582,719,428

NOX Emission Allowance 261,280 389,187 308,215 9,754 450 13,180 1,249,556

Total Fossil Fuel with NOX Allowance 53,031,221 52,963,424 50,706,040 47,029,874 51,774,471 54,074,734 583,968,984

Nuclear 3,426,976 2,433,533 2,978,102 3,337,350 559,999 2,631,146 35,701,100

Total Fuel Expense 56,458,197$ 55,396,958$ 53,684,142$ 50,367,224$ 52,334,470$ 56,705,880$ 619,670,085$

* Expenses tie to Consolidated Income Statement (WP(JRK-1) pages 1 of 48 thru 12 of 48) and P3M (WP(JRK-1) pages 13 of 48 thru 48 of 48).


Page 2 of 2

MPSC Case No. U-_______Witness: S.M. DiGaetanoExhibit No. A-12 (SMD-3)Page 1 of 1

The Detroit Edison CompanyTotal Nuclear Fuel ExpenseFor the year ended December 31, 2004

Front End Regulatory Nuclear FuelMonth/Year Amortization Costs Expense Year To Date

Jan-2004 2,561,344$ 830,889$ 3,392,234$ 3,392,234$ Feb-2004 2,474,372 808,402 3,282,774 6,675,008 Mar-2004 2,608,019 844,732 3,452,751 10,127,759

1st Quarter 7,643,736 2,484,023 10,127,759

Apr-2004 2,542,997 827,044 3,370,041 13,497,800 May-2004 2,630,833 844,882 3,475,715 16,973,515 Jun-2004 2,546,155 814,324 3,360,479 20,333,993

2nd Quarter 7,719,985 2,486,250 10,206,234

Jul-2004 2,601,787 825,189 3,426,976 23,760,969 Aug-2004 1,831,531 602,002 2,433,533 26,194,502 Sep-2004 2,253,256 724,846 2,978,102 29,172,605

3rd Quarter 6,686,575 2,152,037 8,838,611

Oct-2004 2,487,697 849,653 3,337,350 32,509,955 Nov-2004 357,076 202,923 559,999 33,069,954 Dec-2004 1,948,986 682,159 2,631,146 35,701,100

4th Quarter 4,793,759 1,734,736 6,528,495

Year Total 26,844,055$ 8,857,045$ 35,701,100$ -$

MPSC Case No. Witness: S.M. DiGaetanoExhibit No. A-13 (SMD-4)Page 1 of 1

The Detroit Edison CompanyTransmission Expense by MonthFor the year ended December 31, 2004

Total Schedule 10 Schedule 18 TotalSchedule 1 Schedule 7 Schedule 8 Schedule 9 * Schedule 10 Schedule 18 FERC Charges Gross Expense Deferred Deferred Net Expense

January 353,525$ 4,081$ 6,422,229$ 712,176$ 263,592$ 160,579$ 7,916,182$ 712,176$ 263,592$ 6,940,414$ February 362,821 - 6,017,400 660,564 - 160,579 7,201,364 343,493 - 6,857,871 March 274,068 3,015 5,384,168 611,837 470,691 160,579 6,904,359 318,155 244,759 6,341,444 April 303,102 26,966 5,355,025 600,558 136,700 160,579 6,582,931 246,589 56,129 6,280,213 May 366,504 4,422 5,989 6,703,409 733,973 83,333 160,579 8,058,210 301,369 34,217 7,722,624 June 463,192 5,816 8,833,195 863,734 83,333 160,579 10,409,850 354,649 34,217 10,020,984 July 502,085 7,736 9,629,824 967,677 83,333 160,579 11,351,235 397,328 34,217 10,919,690 August 476,380 5,105 9,128,069 902,674 83,333 100,000 10,695,561 370,638 34,217 10,290,707 September 396,946 5,478 7,470,660 779,485 83,333 100,000 8,835,903 320,057 34,217 8,481,629 October 291,254 3,382 5,389,843 603,474 83,333 100,000 6,471,286 247,786 34,217 6,189,283 November 297,631 10,496 5,519,733 607,188 83,333 100,000 6,618,381 249,311 34,217 6,334,853 December 380,283 10 3,135 7,140,423 763,346 83,333 100,000 8,470,529 313,430 34,217 8,122,882

4,467,792$ 4,432$ 81,198$ 82,993,979$ 8,806,685$ 1,537,647$ 1,624,056$ 99,515,790$ 4,174,982$ 838,212$ 94,502,595$

* This schedule includes an accrued network transmission refund of $9,800,000 from International Transmission Company.

MPSC Case No. U-_______ Witness: S.M. DiGaetanoExhibit No. A-14 (SMD-5)Page 1 of 1

The Detroit Edison CompanyTransmission Expense incurred after November 23, 2004For the year ended December 31, 2004

Total Schedule 10 Schedule 18 TotalSchedule 1 Schedule 9 * Schedule 10 Schedule 18 FERC Charges Gross Expense Deferred Deferred Net Expense

November ** 69,447$ 1,287,938$ 141,677$ 19,444$ 23,333$ 1,541,840$ 58,173$ 7,984$ 1,475,683$ December 380,283 7,140,422 763,346 83,333 100,000 8,467,384 313,430 34,217 8,119,738

449,730$ 8,428,360$ 905,023$ 102,777$ 123,333$ 10,009,224$ 371,602$ 42,200$ 9,595,421$

** These amounts reflect prorated expense based on November 23, 2004 MPSC order in MPSC case No. U-13808.

* This schedule includes an prorated accrued network transmission refund from the International Transmission Company of $190,556 and $ 816,667 for the month of November and December, respectively.




QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

TERRY S. HARVILL

THE DETROIT EDISON COMPANY QUALIFICATIONS OF TERRY S. HARVILL

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A. My name is Terry S. Harvill. My business address is The Detroit Edison

Company, 2000 Second Avenue, Detroit, Michigan, 48226.

Q. By whom are you employed and in what capacity?

A. I am currently employed by The Detroit Edison Company (“Detroit Edison,”

“Edison,” or “the Company”) as a Director of Regulatory Affairs. In this

capacity, I am responsible for federal regulatory issues and various state

regulatory issues.

Q. Please describe your formal education.

A. I received a Bachelor of Science degree and a Master of Science degree in

Economics from Illinois State University in 1991 and 1992, respectively. I have

completed all coursework and have been admitted to candidacy for my Ph.D.

in Economics from the University of Illinois at Chicago.

Q. Please describe your professional work experience.

A. I began my professional career in 1992 as an Economic Analyst in the Rate

Design Department of the Public Utilities Division of the Illinois Commerce

Commission (“ICC”). The Illinois Commerce Commission is the State of

Illinois’ public utility commission that regulates electric, natural gas, water, and

telephone utilities operating within the State of Illinois. In that capacity, I

prepared expert written testimony and provided expert oral testimony on

marginal and embedded cost-of-service and rate design issues within the

context of electricity, natural gas, and water rate proceedings before the ICC.

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In 1993, I was promoted to Senior Economist.

From 1994 to 1995, I served as the Senior Policy Advisor to the Chairman of

the Illinois Commerce Commission. In that role, I was the primary strategist to

the Chairman for developing and implementing positions based upon the

analysis of financial, economic, and public policy issues presented in

proceedings before the ICC.

From 1995 to 1998, I served as then Illinois Governor Jim Edgar’s Assistant for

Business and Economic Development. In that capacity, I was responsible for

the development and implementation of the Governor’s economic development

strategy. In addition, I provided legislative analysis and guidance to the

Governor on a wide variety of issues associated with business and economic

development and regulatory policy and operations. I was responsible for

electric, natural gas, and telecommunications restructuring/deregulation

legislative efforts at both the state and federal level including the “Illinois

Electric Service Customer Choice and Rate Relief Law of 1997.”

In 1998, I was appointed by then Illinois Governor Jim Edgar to the Illinois

Commerce Commission. During my tenure on the ICC, I served as the

Chairman of the Commission’s Electric Policy Committee. I served as a

Commissioner until the expiration of my term in January of 2003.

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In 2003, I assumed my current position as a Director of Regulatory Affairs for

The Detroit Edison Company. In this capacity, I am responsible for federal

regulatory issues and various state regulatory issues.

Q. Have you testified previously on regulatory issues?

A. Yes. I have testified on various regulatory matters before the Illinois

Commerce Commission, the Federal Energy Regulatory Commission

(“FERC”), the Illinois General Assembly, the United States House of

Representatives Committee on the Judiciary, and the United States Senate

Committee on Energy and Natural Resources. More recently, I provided

rebuttal testimony in Detroit Edison’s main electric rate case, MPSC Case No.

U-13808.

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THE DETROIT EDISON COMPANY DIRECT TESTIMONY OF TERRY S. HARVILL

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Q. What is the purpose of your direct testimony?

A. My testimony has been prepared to provide an overview of the Detroit Edison

Company’s filing and to make and support recommendations concerning

unresolved policy issues surrounding the 2004 Power Supply Cost Recovery

(“PSCR”) mechanism for the Detroit Edison Company in light of Michigan’s

active electric retail choice environment. In addition, my direct testimony

addresses the Company’s production fixed cost stranded cost calculation for

2004. My testimony is organized as follows:

First, I provide a general overview of the Company’s direct testimony.

Second, I provide an overview of the 2004 PSCR Plan and the events that

transpired in 2004 as they relate to the Company’s power supply costs.

Third, I discuss the Company’s 2004 third party wholesale power sales and

provide a recommendation regarding the appropriate determination of the net

proceeds from such third party wholesale power sales. In addition, I propose

an allocation of such net proceeds as an offset to PSCR expense and

production fixed cost stranded costs.

Fourth, I discuss the production fixed cost stranded cost calculation contained

in the Company’s application.

Fifth, I provide the reasoning for the Company’s proposal to defer

reconciliation of the Pension Equalization Mechanism adopted by the

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Commission in its November 23, 2004, Order in MPSC Case No. U-13808 and

to consolidate the 38 days of 2004 into the 2005 reconciliation.

Finally, I provide a summary of the Company’s final PSCR position and final

net stranded cost position. In addition, I demonstrate that the Company’s

request in this proceeding is reasonable and appropriate in light of Detroit

Edison’s 2004 financial performance.

I. OVERVIEW OF THE COMPANY’S TESTIMONY 9

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Q. Can you please provide a brief overview of Detroit Edison’s testimony

related to its application in this matter?

A. Yes. In addition to my testimony, Detroit Edison is presenting the following

testimony: the explanation and reconciliation related to the PSCR mechanism,

the recovery of production operation and maintenance (“O&M”) expense

associated with third party wholesale power sales, the disposition of net

proceeds from third party wholesale power sales, and the calculation of 2004

production fixed costs stranded costs. The following witnesses address these

issues in detail:

James H. Byron, Manager, Generation Optimization-Power Planning and

Reliability, supports the determination of net proceeds from third party

wholesale power sales, the determination of the appropriate production O&M

costs associated with third party wholesale power sales, the determination of

net proceeds to be assigned to PSCR customers, the amount of net proceeds

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available to reduce 2004 stranded costs, and the actual power supply

operation as compared to the 2004 PSCR Plan.

John C. Dau, Production Manager, Belle River Power Plant, explains the

differences between the 2004 actual and the 2004 planned maintenance of the

Company’s generating system.

Steven M. DiGaetano, Supervisor, Financial Management, provides the

accounting support for Account 555 (Purchased Power Expense), Account 565

(Transmission Provided by Others), Account 447 (Sales for Resale), Accounts

501 and 547 (Fossil Fuel Expense), Account 518 (Nuclear Fuel Expense), and

Account 509 (NOx Emission Allowance Expense).

David H. Hicks, Supervisor, Business Development and Administration, Fuel

Supply, reconciles the difference between the 2004 actual unit cost of fossil

fuel expense and the corresponding 2004 PSCR Plan costs.

Kevin L. O’Neill, Principal Project Manager, Regulatory Policy and Operations,

reconciles Detroit Edison’s 2004 power supply cost recovery (PSCR) revenues

and expenses including the third party wholesale power sales net proceeds

calculated by Mr. Byron.

Martin L. Heiser, Consultant, Regulatory Economics, Regulatory Policy and

Operations, addresses the development of the revenue allocation for

production fixed costs and production O&M. Mr. Heiser addresses the

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revenue allocation for the three different stranded cost recovery periods during

2004 -- pre-interim, interim, and post final order.

Rishi S. Sadagopan, Principal Financial Analyst, Regulatory Policy and

Operations, supports the 2004 revenue available for production fixed costs and

production O&M and also determines the 2004 net stranded costs to be

recovered from Electric Choice customers.

Edward L. Falletich, Manager of Pricing, Regulatory Affairs Department,

develops the appropriate surcharge to recover Detroit Edison’s 2004 net

stranded costs.

II. DETROIT EDISON’S 2004 PSCR PLAN AND RECONCILIATION 13

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Q. What were the key components of Detroit Edison’s 2004 PSCR Plan?

A. Detroit Edison’s 2004 PSCR Plan was submitted in conjunction with the

Company’s main electric rate case, MPSC Case No. U-13808, to determine

the net proceeds from third party wholesale power sales and to obtain specific

direction from the Commission with respect to the disposition of the net

proceeds from the third party wholesale power sales.

The Company proposed that the PSCR mechanism be restarted in

combination with a mitigation adjustment to ensure that any stranded costs

associated with the Company’s retail Electric Choice program would be offset

by the sale of the freed-up power and energy via third party wholesale power

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sales. In the alternative, the Company recommended that the PSCR

mechanism should remain frozen until appropriate rate relief and direction

relative to the disposition of third party wholesale power sales was provided.

Q. Why was the Company seeking either the concurrent restart of the PSCR

mechanism with a mitigation adjustment or the delayed re-establishment

of the PSCR mechanism?

A. Prior to the advent of Electric Choice, third party wholesale power sales

revenue flowed through the PSCR mechanism, effectively resulting in a credit

to PSCR customers. However, during the PSCR freeze period, June 2000

through December 2003, the Commission utilized third party wholesale power

sales net revenue to offset stranded cost. Therefore, absent a definitive

determination by the Commission regarding the prospective disposition of third

party wholesale power sales, it was unclear how third party wholesale power

sales would be treated once the PSCR mechanism was re-established.

Clearly, third party wholesale power sales revenue cannot be used more than

once. For example, if the Commission required that third party wholesale

power sales revenue be returned to PSCR customers, as it was prior to the

rate freeze, then the stranded costs associated with the Company’s retail

electric choice program would be greater since the net proceeds from third

party wholesale power sales would not be available to offset such stranded

costs.

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Q. How were third party wholesale power sales assumed to be applied in

the Company’s PSCR Plan case?

A. The Company’s 2004 PSCR Plan reflected a traditional PSCR component of a

negative 1.05 mills per kWh as well as a mitigation component of a positive

3.23 mills per kWh. The net PSCR factor reflected a credit from third party

wholesale power sales and a reduction in purchased power to the PSCR

mechanism. The amount of capacity available to make these sales was based

upon estimates of Electric Choice sales, bundled customer sales, plant

generation, power purchases, and expected third party wholesale sales

revenues.

Q. Did any of the 2004 PSCR Plan considerations change from the time that

the 2004 PSCR Plan was filed in June 2003?

A. Yes. Many of the assumptions that were used to develop the plan changed in

the ensuing 18 months. These changes included the volume and timing of

Electric Choice sales, the volume of bundled customer sales, the amount of

power purchases, the availability of generation plant, the increase in wholesale

market prices, and the average revenue from third party wholesale power

sales.

Q. What changes occurred with respect to the Electric Choice volumes?

A. The Company had forecasted 2004 Electric Choice sales of 8,940 GWhs. This

forecast assumed that Special Manufacturing Contract (“SMC”) customers

would migrate to Electric Choice in the fourth quarter of 2004, an expectation

that was never realized. However, the Company did not anticipate the effect of

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the July 31, 2003 Order in its Stranded Cost Recovery Case, Case No U-

13350. The issuance of this Order (continuation of the zero mill transition

charge, the Electric Choice securitization bond and tax charge offsets, and the

Electric Choice equalization credit) led to a significant and greater than

anticipated increase in Electric Choice enrollment activity.

Q. What were the changes to bundled customer sales?

A. During 2004, Detroit Edison experienced cooler summer temperatures, and

this fact, combined with the greater than anticipated increase in Electric Choice

program participation, led to significantly lower bundled customer sales than

forecast.

Q. What were the changes with respect to plant generation, power

purchases, and third party sales revenues?

A. As explained by Company witness James Byron, both Detroit Edison plant

generation and power purchases exceeded amounts forecast in the 2004

PSCR Plan, both at a lower average cost. Additionally, the average revenue

realized from the third party wholesale power sales exceeded that which was

forecast in the 2004 PSCR Plan.

Q. How did all of these changes impact the operation of the Detroit Edison

system in 2004?

A. All of these changes collectively allowed Detroit Edison to make third party

wholesale power sales totaling almost 6,100 GWh with total revenues of over

$217 million. This is much higher than the forecasted 2004 PSCR Plan sales

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of only 1,850 GWh and projected revenues of almost $58 million.

Q. Did Detroit Edison return these revenues to PSCR customers by lowering

the PSCR factor?

A. No. Detroit Edison continued to charge PSCR customers the same PSCR

factor and, ultimately, lacking specific direction from the Commission, reflected

the revenues from third party wholesale power sales as credits to the PSCR

mechanism in its monthly 45-day reports.

Q. Why did Detroit Edison not return these revenues to PSCR customers?

A. Detroit Edison did not return these revenues to PSCR customers because, as I

discussed earlier, it did not have specific Commission direction with respect to

disposition of these proceeds. Prior to suspension of the PSCR mechanism,

all revenues from third party wholesale power sales were credited to the PSCR

mechanism to reduce PSCR expense. However, during the period in which

the PSCR mechanism was frozen, the net proceeds from third party wholesale

power sales were utilized by the Company to reduce overall stranded costs. In

the conjoined PSCR Plan/Main Electric Rate proceedings, Detroit Edison

requested specific direction from the Commission regarding the disposition of

these third party wholesale power sales. The Commission’s Final Order did

not provide such direction beyond the following:

“Given the Commission’s decision not to adopt the “slice of generation” proposal, and because the rate caps will remain in effect until January 1, 2006, it is clear that there will be a need for a comprehensive true-up of the 2004 PSCR and production fixed cost stranded cost calculations. Detroit Edison shall file its

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2004 stranded cost case in conjunction with its PSCR reconciliation case to ensure a comprehensive evaluation of its stranded costs including equitable treatment of interconnection/third party revenues.” (MPSC Case No. U-13808 Order dated November 23, 2004, p. 106)

Q. Were there other factors that led to the Company’s decision to maintain

the PSCR factor at the Commission-ordered level (-1.05 mills/kWh)

despite the fact that the Company was in an over-collected position when

third party wholesale power sales were included in the calculation?

A. Yes. The February 20, 2004, Interim Order in Case No U-13808 provided rate

increases to different classes of customers, capped and uncapped, in different

fashions. The uncapped customers received the increase in the form of a

straight percentage, whereas the capped customers received a specific base

rate increase amount that was equal to the difference between the frozen

PSCR factor and the 2004 PSCR Plan factor for an increase of 2.99 mills/kWh

for residential customers and 3.09 mills/kWh for small commercial customers

with demands less than 15 kW. The manner in which this was accomplished

eliminated the Company’s ability to increase base rates any further for capped

customers if it decreased the PSCR factor to reflect the impact of reduced

purchases and third party wholesale power sales. In light of the uncertainty

regarding the ultimate disposition of the third party wholesale power sales, it

would have been imprudent to lower the PSCR factor. Lowering the factor

would have provided a rate reduction for customers whose rates were capped

without any ability to offset such a reduction with a corresponding base rate

increase.

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Second, PSCR customers had received a significant benefit from Electric

Choice in that the Company was able to avoid significant expenses associated

with purchased power costs. This benefit was realized through the lower

PSCR factor of a negative 1.05 mills per kWh. As Mr. Byron illustrated in his

testimony in MPSC Case No. U-13808 regarding the mitigation adjustment, the

PSCR factor would have been 3.23 mills per kWh higher without the existence

of Electric Choice.

Finally, it was and remains inappropriate to assign PSCR customers 100% of

the benefits (revenues from third party wholesale power sales and reduced

purchased power costs) from the Company’s generation assets when they

were not paying for 100% of the costs of the assets.

III. 2004 THIRD PARTY WHOLESALE POWER SALES AND THE 14

DETERMINATION OF NET PROCEEDS 15

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Q. Can you explain the key components of Detroit Edison’s 2004 PSCR

Reconciliation?

A. Yes. As I previously indicated, Detroit Edison made third party wholesale

power sales totaling almost 6,100 GWhs with revenues totaling over $217

million. For purposes of the 45-day reports, Detroit Edison credited the entire

amount of the wholesale power sales revenue to the PSCR customers

throughout 2004 with the intention of adjusting that methodology upon the

issuance of further guidance in the Final Order in MPSC Case No. U-13808.

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Q. Did Detroit Edison obtain the direction it needed from the Final Order in

MPSC Case No. U-13808?

A. No. As previously noted, although the record in MPSC Case No. U-13808 led

Detroit Edison to believe that it would likely be able to utilize at least 90% of

the net proceeds from third party wholesale power sales to recover its

production related stranded costs dating back to the Interim Order (MPSC

Case No. U-13808, Direct Testimony of George J. Stojic, 14 T 3139-3141), the

Commission’s Final Order still left in question the appropriate disposition of the

revenues from the third party wholesale power sales.

Q. How is the Company proposing that the net proceeds from third party

wholesale power sales be determined?

A. Consistent with precedent in prior stranded cost proceedings, particularly

MPSC Case No. U-13350, Mr. Byron has proposed that the net proceeds from

the third party wholesale power sales be determined based on an average

cost. Specifically, the third party wholesale power sales net proceeds would

be determined by reducing the total third party wholesale sale revenues initially

by the average fuel cost. As determined by Mr. Byron, this calculation would

yield proceeds, net of fuel expense, of approximately $127 million.

Q. Does Detroit Edison incur any costs in addition to production fixed costs

when making sales from its generation that has been freed up by

customer migration to Electric Choice?

A. Yes. Detroit Edison incurs both production fixed costs and production

operation and maintenance expenses. The Commission has prescribed a

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methodology by which the Company can recover its unrecovered production

fixed costs but has not provided a relief mechanism for the Company’s costs

associated with production O&M expenses.

Although the Commission has stated previously that production O&M expense

is a variable cost, and thus avoidable (December 20, 2001, Order in MPSC

Case No. U-12639, p. 17), in reality, the only way to truly avoid production

O&M expense is to shut down generating facilities. However, the Company

did not shut down any generating facilities in 2004 for two very important

reasons. First, the Company was and remains committed to maintaining the

reliability of the electric system in Southeast Michigan. To shut down a

generating facility given the various electric supply issues in 2004 in order to

avoid the production O&M expense would not have been prudent. Second,

the Company was given specific direction by the Commission (December 20,

2001, Order in MSPC Case No. U-12639 adopting the Commission Staff’s

methodology regarding the calculation of net stranded costs and stated that

the methodology shall be carried forward) to mitigate stranded costs by selling

the power and energy freed up due to the Electric Choice program via third

party wholesale power sales. Clearly, one cannot sell power and energy from

a generating facility if the generating facility is not operating. Similarly, one

cannot sell power and energy without incurring some level of production O&M

expense.

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Q. Was the Company able to avoid any expense related to production O&M

during 2004 when making sales from its generation that has been freed

up by the migration of customers to Electric Choice?

A. No. In fact, the Company actually incurred production O&M expense well

above that approved in base rates in the November 23, 2004, Order in MPSC

Case No. U-13808. As I discussed previously, the Company was directed to

mitigate its stranded costs by making third party wholesale power sales. It was

therefore unable to avoid the production O&M expense related to making third

party wholesale power sales. Thus, the revenues from third party wholesale

power sales should be reduced by not only the average fuel cost, but also by

the average production O&M cost.

Q. How should the average production O&M cost be determined?

A. Consistent with the Commission’s prior use of average fuel cost, I would

recommend that average production O&M cost be used in the determination

based upon the actual 2004 generation and actual 2004 production O&M

expense. This methodology would allow Edison to recover the production

O&M expense directly related to the third party wholesale power sales. Mr.

Byron calculates the adjustment according to this methodology.

Q. Would the recovery of this production O&M expense from selling power

and energy from freed up generation allow Edison to recover its total

production O&M expense?

A. No, it would not. In 2004, the Company incurred approximately $412 million in

production O&M expense, excluding indirects. Of that, approximately $275

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million was recovered from bundled customers via bundled rates. The

methodology outlined above would provide an additional $74 million

contribution to 2004 unrecovered production O&M expense. This would still

result in a shortfall of production O&M expense of over $60 million.

Q. Based upon the Company’s operations in 2004, do you have a

recommendation with respect to allocation of the net proceeds from third

party wholesale power sales?

A. Yes. The benefits resulting from third party wholesale power sales should be

fairly allocated to those that paid for the right to the benefits. According to Mr.

Sadagopan, the production fixed cost revenue requirement for 2004 was

approximately $507 million. Bundled customers contributed approximately

$384 million to the recovery of the production fixed cost revenue requirement.

Assuming that Electric Choice customers fully contribute the difference

between the 2004 production fixed cost revenue requirement and that which

was actually collected from bundled customers in 2004, I would propose that

the net proceeds from third party wholesale sales be allocated in a similar

proportion. This would result in approximately 76 percent of the net proceeds

from third party wholesale power sales being allocated to bundled customers

and 24 percent of the net proceeds from third party wholesale power sales

being allocated to Electric Choice customers in the form of a lower total

stranded cost responsibility. Mr. Byron has utilized the 76/24 ratio to allocate

the net proceeds from third party wholesale power sales and the resulting

values are utilized by Mr. O’Neill in his PSCR reconciliation and Mr.

Sadagopan in his net stranded cost calculation.

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Q. How would your recommendation change if Electric Choice customers

do not fully contribute the difference between the 2004 production fixed

cost revenue requirement and that which was actually collected from

bundled customers in 2004?

A. As noted previously, the benefits resulting from third party wholesale power

sales should be fairly allocated to those that paid for the right to the benefits. If

Electric Choice customers are not contributing to the recovery of production

fixed costs then they should not enjoy the benefits of the third party wholesale

power sales net proceeds. Assuming, for example, that bundled customers

were ultimately assigned responsibility for the entire $507 million production

fixed cost revenue requirement for 2004, then bundled customers should

receive the full benefit of the third party wholesale power sales net proceeds.

Similarly, if any responsibility for 2004 production fixed costs should fall to the

Company, then the Company should receive a proportionate share of the

benefits of the third party wholesale power sales net proceeds.

IV. 2004 PRODUCTION FIXED COST STRANDED COST METHODOLOGY 17

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Q. Do you have any recommendations with respect to the methodology that

the Commission utilized in the determination of Detroit Edison’s

production fixed cost stranded costs?

A. Yes. The Company has basically adopted the production fixed cost stranded

cost methodology that was approved by the Commission in its Order in MPSC

Case No. U-13808. However, with an active PSCR clause, some

modifications must to be made to the calculation of production revenues to

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ensure that Public Act 141 comports with Public Act 304.

Specifically, an active PSCR mechanism allows the Company to obtain

revenues that are equal to its prudent and reasonable fuel and purchased

power expenses. The revenue that is collected for this purpose is dedicated to

cover the associated expense and therefore cannot be considered as revenue

to be allocated to production fixed costs. To be consistent, the production

fixed cost revenue allocation factor must also be adjusted for the removal of

the PSCR expense that is contained in base rates. The effect of this

modification allows the PSCR revenues to be reconciled with PSCR expense

without diverting any of the revenues to cover production fixed costs. Mr.

Heiser and Mr. Sadagopan discuss the details of this modification in more

detail in their testimony.

Q. Do you recommend any other modifications to the methodology that the

Commission used in the determination of production fixed cost stranded

costs?

A. Yes. For the purposes of determining the Production Fixed Cost Revenue

percentages for the three rate periods during 2004, the Company utilized the

rates established in the January 21, 1994 Order in MPSC Case No. U-10102

for the pre-interim period, and the rates established in the November 23, 2004,

Order in MPSC Case No. U-13808 for the post-final period. However, it was

necessary for the Company to modify the production fixed costs established in

the February 20, 2004 Interim Order in MPSC Case No. U-13808 to reflect that

a portion of the rate relief associated with production fixed costs was not

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provided until the Final Order.

Therefore, the Company utilized the Final Order in MPSC Case No. U-13808

and its recently filed rate unbundling and realignment case, MPSC Case No.

U-14399, as the basis for determination of its production fixed cost revenue

allocation for the interim period. The Company simply started with the Staff’s

interim relief recommendation and adjusted it for the additional relief that the

Company was provided in the Final Order. Specifically, the Company received

additional rate relief for the increased Electric Choice sales (9,250 GWh versus

7,565 GWh) and the removal of the imputation of revenues with respect to

SMC customers.

Q. Why is the Company calculating stranded cost for the entire calendar

year of 2004 given that the Commission provided relief up to the Interim

Order in MPSC Case No. U-13808?

A. The Company is recalculating the net stranded cost for the entire year 2004 for

several reasons. First, the relief provided for the pre-interim period simply

used the calculation for 2003 and pro-rated that calculation for 51 days in

2004. This presents a problem since third party wholesale power sales net

revenues were credited to stranded costs in 2003. Given that the PSCR

mechanism was restarted on January 1, 2004, the Commission must now

determine how third party wholesale power sales revenues are to be utilized.

In addition to the disposition of third party wholesale power sales net revenues,

there was a significant increase in Electric Choice sales in 2004, and therefore

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the Company received a much lower contribution to production fixed costs in

2004. It is extremely important to properly calculate stranded costs for the

entire year in a consistent and verifiable manner. In the final analysis, the net

stranded cost amount ordered for the pre-interim period in MPSC Case No. U-

13808 will be credited to the total 2004 calendar year amount.

V. OVERVIEW OF THE COMPANY’S PROPOSAL WITH REGARD TO THE 7

COMMISSION’S ADOPTION OF THE PENSION EQUALIZATION 8

MECHANISM (“PEM”) 9

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Q. Can you explain the Company’s proposal for compliance with the filing

of the Pension Equalization Mechanism reconciliation in conjunction

with the PSCR Reconciliation?

A. Yes. Detroit Edison proposes that the reconciliation for the 2004 Pension

Equalization Mechanism be deferred for inclusion in the reconciliation of the

2005 Pension Equalization Mechanism. The Pension Equalization Mechanism

was approved in the November 23, 2004 Order in MPSC Case No. U-13808

and was only in place for the last 38 days of 2004. Due to the short time

period to be reconciled and the complexity of this filing, it is appropriate to

defer the 2004 PEM reconciliation to the 2005 PSCR Reconciliation

proceeding.

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Q. Has the Company developed a position with respect to the Pension

Equalization Mechanism reconciliation?

A. No. Although the Company booked an estimated liability of $454,000 for 2004,

it has not performed a detailed reconciliation for the post-interim period for the

Pension Equalization Mechanism. It is expected that the impact of the 2004

PEM reconciliation would be de minimus.

VI. FINAL PSCR POSITION, NET STRANDED COST POSITION, AND 8

PROPOSED NET STRANDED COST RECOVERY MECHANISM 9

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Q. Assuming that Detroit Edison’s recommendations are accepted with

respect to the distribution of the net third party wholesale power sales

proceeds, what is the Company’s final PSCR position?

A. According to Mr. O’Neill’s direct testimony, after receiving a credit from the

third party wholesale power sales net proceeds on a 76/24 basis, the PSCR

mechanism would be over-collected by approximately $8 million.

Q. How would you propose to distribute that amount to PSCR customers?

A. I would request that the Commission allow the Company to credit that amount

to PSCR customers through a 2005 PSCR factor credit.

Q. What amount of net stranded cost would be recoverable from Electric

Choice customers given a 76/24 split of net third party wholesale power

sales proceeds?

A. According to Mr. Sadagopan’s direct testimony, the net stranded cost would be

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approximately $99 million.

Q. How does this net stranded cost figure compare with that recorded by

the Company for stranded costs in 2004?

A. The Company recorded a regulatory asset for 2004 stranded costs of

approximately $107 million. This number compares to the 2004 stranded cost

number calculated by Mr. Sadagopan of approximately $112 million (before

adjusting for the third party wholesale power sales credit). This regulatory

asset represents over 46 percent of the total 2004 net income for The Detroit

Edison Company. Absent the inclusion of this regulatory asset, the Company

would have earned approximately $80 million, or less than a three percent

return on common equity. This compares to the Company’s authorized return

on common equity of 11 percent that equates to a net income of $332 million.

Without question, 2004 was a financially difficult year for The Detroit Edison

Company; the inability to recover 2004 net stranded costs would undoubtedly

make a financially difficult situation even worse.

Q. What events occurred in 2004 that led to the Company incurring stranded

costs of this magnitude?

A. A number of events occurred in 2004 related to the Company incurring

significant stranded costs for 2004. Chief among these events were a

dramatic increase in Electric Choice sales, the restart of the PSCR mechanism

on January 1, 2004, that effectively eliminated the Company’s ability to retain

third party wholesale power sales net proceeds to mitigate stranded costs via

third party wholesale power sales and avoided power purchases, an

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underestimation of 2004 Electric Choice sales in the Interim Order in Case No.

U-13808, and the existence of statutorily imposed rate caps for the Company.

Q. How would you propose to recover the calculated net stranded costs?

A. I would recommend that the existing Electric Choice transition charge be

continued until a final determination of net stranded costs is made in this case.

This would send the proper economic signals to Electric Choice customers and

would avoid the stopping and restarting of a transition charge.

Consistent with Mr. Falletich’s direct testimony, once a final 2004 stranded

cost amount is determined the Commission should implement a secondary

Electric Choice transition charge of 0.45¢/kWh and a primary Electric Choice

transition charge of 0.15¢/kWh.


A. Yes, it does.

TSH - 24




QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

DAVID H. HICKS

THE DETROIT EDISON COMPANY QUALIFICATIONS OF DAVID H. HICKS

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Q. Please state your name and position.

A. My name is David H. Hicks. My position is that of Supervisor, Business

Development and Administration, Fuel Supply.

Q. What is your business address?

A. My business address is 2000 Second Avenue, Detroit, Michigan 48226.

Q. Please state your educational background.

A. My formal education consists of a Bachelor of Science degree in Mechanical

Engineering from the University of Michigan. I have also completed several

Company sponsored courses and have attended various seminars to further

my development with Detroit Edison.

Q. Please summarize your professional experience.

A. In 1982 I joined Detroit Edison and was assigned to the Production

Organization (later named Fossil Generation) as an assistant engineer at the

Greenwood Energy Center. In this position I worked on various projects

related to improving unit operation and maintenance.

In 1984 I was assigned as a start-up engineer for Belle River Unit No.2. My

responsibilities included the check-out and initial operation of several turbine

related systems.

In 1985 I was assigned as a unit engineer in the Technical Group at St. Clair

Power Plant. My responsibilities included providing technical support to the

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Plant’s Maintenance and Operation Groups.

In 1992 I was assigned as a Team Leader for the Unit Engineer Group, then

later the Plant Improvement Projects Group. My responsibilities included

directing the technical support and plant improvement activities of the

engineers and technicians assigned to these groups.

In 1994 I was assigned to the Maintenance Group as an Outage Manager. My

responsibilities included directing the maintenance activities of periodic and

forced unit outages.

In January 1995 I began a cross-training assignment in Business Development

and Administration, Fuel Supply and joined Fuel Supply permanently as a

Specialist - Fuel Resources in October 1995. While in Fuel Supply my

responsibilities included the administration of long-term coal and rail

transportation contracts, assisting in the generation of short and long-term fuel

plans and the analysis of fuel budget variances. These broad responsibilities

encompass specific activities such as the development of the fossil fuel portion

of the Company’s operating budget; the monitoring of existing contract

performance for conformance to contract terms and conditions; contract

buyouts, and buydowns; and the negotiation of tonnage, price and other terms

and conditions of new long-term contracts. In May 1997, I was promoted to

the position of Supervisor in which my primary responsibility is to direct the

activities of the Specialists - Fuel Resources.

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Q. To what extent have you participated in rate proceedings before

regulatory commissions?

A. I have provided support for the fossil fuel expense witness in Power Supply

Cost Recovery Case Nos. U-10427-R, U-10702-R, U-10965 and the Main

Electric Rate Case No. U-13808. I was the fossil fuel expense witness in Case

Nos. U-10965-R, U-11175, U-11175-R, U-11528, U-11528-R, U-11800, U-

12121, and U-14275.

DHH - 3

THE DETROIT EDISON COMPANY DIRECT TESTIMONY OF DAVID H. HICKS

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A. The purpose of my testimony is to reconcile the difference between the 2004

actual unit cost of fossil fuel expense and the corresponding planned costs

from the 2004 PSCR Plan.

Q. What is the purpose of Exhibit No. A-15 (DHH-1)?

A. Exhibit No. A-15 (DHH-1) Unit Fuel Cost Comparison, compares the 2004

actual unit cost of fuel expense with the 2004 PSCR Plan forecast costs.

Despite increasing fossil fuel prices in 2004, through prudent contracting and

resource management the Company was able to keep 2004 fossil fuel

expenses in check. Actual expenses were in fact slightly lower than expected.

Q. What items significantly contributed to the difference between 2004

actual costs and the 2004 PSCR Plan forecast costs for coal?

A. The actual unit cost of coal expense was 2.8% higher than the forecasted unit

cost. Eastern coal market prices in 2004 increased nearly 100% compared to

the market prices at the time the 2004 PSCR Plan forecast was prepared in

April 2003. The Company minimized the impact by having already entered into

long-term contracts that had prices much lower than the market coal prices

experienced in 2004. In addition, the impact of higher eastern coal prices was

mitigated by changing coal blends (i.e., low sulfur western coal blends were

increased) whenever economically and operationally possible.

An increase in transportation costs also contributed to the higher than

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forecasted unit cost of coal expense. This can be attributed to an increase in

fuel oil costs paid by the railroads and vessel companies delivering coal to the

Company’s power plants. On the other hand, the higher than forecasted unit

cost of coal expense was offset somewhat by higher than forecasted third

party revenues generated at the Company’s Midwest Energy Resources

Company (MERC) transshipment facility.

Q. What items significantly contributed to the difference between 2004

actual costs and the 2004 PSCR Plan forecast costs for oil and natural

gas?

A. The actual unit cost of No.2 oil, No.6 oil, and natural gas expense were higher

than the forecasted unit costs by 45.0%, 27.7%, and 36.5%, respectively. The

market costs for these commodities were significantly higher than forecasted

as a result of such influences as the weather (i.e., a severe hurricane season)

and world pressures (i.e., Middle East volatility, high global demand for oil).

Q. What caused the difference between the 2004 actual unit costs and the

2004 PSCR Plan unit costs for blast furnace and coke oven gas?

A The actual unit cost of blast furnace and coke oven gas expense was 112.4%

higher than the forecasted unit cost. The total expense and heat consumption

of blast furnace and coke oven gas in 2004 were very small ($25,395 and

10,612 MMBtu, respectively) due to the expiration of the blast furnace and

coke oven gas supply contracts. New contracts were not executed as

anticipated in the 2004 PSCR Plan.

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Q. What caused the difference between the 2004 actual unit cost and the

2004 PSCR Plan unit cost for fossil fuel?

A Higher than forecasted coal consumption and lower than forecasted natural

gas consumption resulted in an actual unit cost of fossil fuel of 145¢/MMbtu

compared to a forecasted unit cost of 147¢/MMbtu.

Q. What is your opinion regarding the fuel expenses incurred during 2004?

A. I believe that the Company’s 2004 fossil fuel expenses were reasonable and

the result of prudent fuel procurement policies and practices. A majority of the

Company’s coal requirements for 2004 were fulfilled by aggressively burning

low sulfur western (LSW) coal at various Company power plants and by

burning eastern coal when necessary and prudent, which were priced under

long-term eastern coal contracts that were significantly lower than the

prevailing eastern coal market prices. The LSW supply option was not only

economical but also among the cleanest coals available. The amount of LSW

coal that is burned is a dynamic function of the particular conditions at the

time. Wherever and whenever possible, the units economically blend low, mid,

and high sulfur eastern coals with LSW coals. System load requirements,

equipment capabilities, environmental regulations, and economics are used to

determine the appropriate blend.

The Company continued to aggressively market coal and transshipment

services to third parties through its subsidiary, MERC. Third party revenues

and the equity received from MERC’s joint venture contributed to a significant

reduction in Detroit Edison fuel expense and thus, ultimately, the electric rates

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for Detroit Edison electric customers.


A. Yes.

DHH - 7




EXHIBIT

OF

DAVID H. HICKS

Case No. U-_______ Witness D.H. Hicks Exhibit No. A-15 (DHH-1) Page: 1 of 1 Michigan Public Service Commission The Detroit Edison Company Unit Fuel Cost Comparison 2004

Line No. 1 2004 2004 PSCR PERCENTAGE 2 ACTUAL PLAN DIFFERENCE 3 FUEL TYPE ¢/MMBtu ¢/MMBtu ACTUAL PLAN 4 5 COAL 135.1 131.4 2.8% 6 7 No.2 OIL 815.5 562.6 45.0% 8 9 No.6 OIL 434.4 340.0 27.8% 10 11 TOTAL OIL 503.8 389.3 29.4% 12 13 NATURAL GAS 684.7 501.6 36.5% 14 15 BLAST / COKE OVEN GAS 239.3 112.7 112.4% 16 17 TOTAL GAS 683.4 471.6 44.9% 18 19 TOTAL SYSTEM - FOSSIL 144.6 146.6 -1.4% 20 21 NUCLEAR 39.8 39.2 1.6% 22 23 TOTAL SYSTEM 125.6 126.9 -1.0% 24 25 Note: Unit fuel costs represent total Electric Department fuel expense including industrial steam.




QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

KEVIN L. O’NEILL

THE DETROIT EDISON COMPANY QUALIFICATIONS OF KEVIN L. O’NEILL

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Q. What is your name and business address, and by whom are you

employed?

A. My name is Kevin L. O’Neill. My business address is 2000 Second Ave.,

Detroit, Michigan 48226. I am employed by The Detroit Edison Company.

Q. What is your current position with Detroit Edison?

A. I am a Principal Project Manager in the Regulatory Policy & Operations

Organization.


A. In 1976, I received a Bachelor of Arts degree from Michigan State University.

My major field of study was Economics. In 1983, I received a Master of

Science degree in Economics from Southern Illinois University. My major field

of study was econometrics. In addition, I have taken graduate courses in

accounting and finance at the University of Detroit and at Wayne State

University.

Q. Please review your employment history with Detroit Edison.

A. I joined Detroit Edison in February of 1978 as an Associate Business Analyst

in the Load Research Department. My major responsibilities were to assist

with the preparation of workpapers and exhibits for rate cases, prepare

monthly load survey reports, and participate in various aspects of a growing

load survey program, e.g., sample selection and validation.

KLO - 1

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In August 1980, I accepted a position in the Revenue Requirement

Department and was assigned to the Economic Studies and Depreciation

Division. In February 1983, I was promoted to the position of Cost Analyst in

the Cost of Service Division of the Revenue Requirement Department. In July

1986, I was promoted to Senior Analyst in the Revenue Requirement

Department. During this time, I analyzed proposed legislation on utility-related

matters, participated in special studies related to marginal cost and

interruptible load, developed computer programs for cost and revenue

requirement studies, prepared bills for special contract customers, and

assisted in depreciation, economic and fuel-related studies. My responsibilities

included performing cost of service studies for electric and steam customers,

analyzing alternative cost of service methodologies, and reviewing accounting,

tax, and regulatory practices and proposals that impact the cost of service.

I was temporarily assigned to the Regulatory Compliance Department in

February 1995. In April 1996, I was promoted to Principal Analyst in the

Revenue Requirement Department. I was responsible for economic and policy

studies related to electric restructuring, for managing various FERC and MPSC

filings, and advising on the financial aspects of nuclear decommissioning. In

March of 1998, I was reassigned to the Regulatory Compliance Department.

In June 2004, I was promoted to my current position.

Q. What are your duties and responsibilities in your current position?

A. I am responsible for coordinating and managing various MPSC filings and

other regulatory issues. Additionally, I serve on the DTE Nuclear

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Decommissioning Trust Committee.

Q. What has been your involvement in PSCR Plan and Reconciliation

cases?

A. I testified concerning Detroit Edison's projected PSCR billing factors for the

following PSCR Plan Cases.

1994 Plan Case No. U-10427







I testified concerning the reconciliation of PSCR revenues and expenses in the

following PSCR Reconciliation proceedings.

1995 PSCR Reconciliation Case No. U-10702-R




Q. What has been your other involvement in rate case activities?

A. I testified regarding Detroit Edison's marginal and embedded cost of

streetlights in Case No. U-9499. I also testified concerning Detroit Edison’s

interest rate proposal for loans under the Home Insulation Finance Program in

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Case No. U-8761.

I was the case manager of Detroit Edison’s Request for Proposals and Retail

Wheeling Implementation Case (No. U-10840); Detroit Edison’s Storm Case

(No. U-10908); Detroit Edison’s Non-Nuclear Depreciation Case (No. U-

11722); the Ludington Depreciation Case (No. U-11724); the ABATE

Complaint Against Detroit Edison Case (No. U-11495); Detroit Edison’s Rate

Unbundling Case (No. U-13286) and the remand of Detroit Edison’s Storm

Amortization Case (No. U-11588-R).

Additionally, I have managed the following pole attachment-related cases.

Pole Attachment Tariff Case No. U-10831

XO Communications Case No. U-13054

Commission’s Show Cause Case No. U-13522

Lake Orion Community Schools Case No. U-13767

McLeodUSA Case No. U-14038

Allen Park Public Schools Case No. U-14170

Woodhaven-Brownstown School District Case No. U-14241

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THE DETROIT EDISON COMPANY DIRECT TESTIMONY OF KEVIN L. O’NEILL

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A. The purpose of my testimony is to reconcile Detroit Edison’s 2004 power

supply cost recovery (PSCR) revenues and expenses.

Q. Are you sponsoring any Exhibits?

A. Yes, I am sponsoring five exhibits, all of which were prepared by me.

Exhibit No. A-16 (KLO-1) Power Supply Expenses and Direct Assignments

Exhibit No. A-17 (KLO-2) Monthly Over (Under) Recovery –

Uncapped Customers

Exhibit No. A-18 (KLO-3) Monthly Over (Under) Recovery –

Adjustment for Capped Customers

Exhibit No. A-19 (KLO-4) Calculation of Billing Factors –

Uncapped Customers

Exhibit No. A-20 (KLO-5) Calculation of Billing Factors –

Capped Customers

Exhibit No. A-16 (KLO-1) shows the development of the various elements used

in the calculation of the recoverable PSCR expense needed to develop

monthly PSCR over (under) recoveries.

Exhibit No. A-17 (KLO-2) calculates the actual monthly over (under) recoveries

of PSCR expense for customers on Industrial and Large Commercial rates

whose rates were not capped during the 2004 PSCR reconciliation period.

Exhibit No. A-18 (KLO-3) shows the calculation of the adjustment for capped

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customers due to the deferred transmission expense for Residential and Small

Commercial customers whose rates were capped during the 2004 PSCR

reconciliation period.

Exhibit No. A-19 (KLO-4) provides alternative calculations, depending on the

month of refund, of the credit billing factors associated with the PSCR over-

recovery for Industrial and Large Commercial customers whose rates were not

capped during the 2004 PSCR reconciliation period.

Exhibit No. A-20 (KLO-5) provides alternative calculations, depending on the

month of refund, of the credit billing factors associated with the PSCR over-

recovery for Residential and Small Commercial customers whose rates were

capped during the 2004 PSCR reconciliation period.

Q. What is the reason for calculating separate 2004 PSCR refund factors for

capped and uncapped customers?

A. The November 23, 2004 Order in Case No. U-13808 stated:

“The Commission finds that the MISO costs, including 2005 projections and Schedule 9 network transmission cost increases, should be recovered through the PSCR mechanism. In the event that such costs are not recovered through the PSCR, particularly as related to customers who remain under rate caps, then such costs shall be recovered through the reconciliation of the RARS.” (Order at page 67)

Both the capped and uncapped customers are in an undercollected position

prior to the assignment of any PSCR credit from third party wholesale power

sales net proceeds. The Company’s undercollected amount exceeds the

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amount of deferrable MISO expense and the expense is therefore deferrable

for capped customers. Therefore, Edison has calculated separate factors for

capped and uncapped customers and recorded the deferrable amount of

MISO expense associated with customers under rate caps in 2004 as a

regulatory asset to be recovered from those customers through the Regulatory

Asset Recovery Surcharge (RARS).

Q. Can you explain Exhibit No. A-16 (KLO-1)?

A. Yes. The total booked cost of Electric Department Fuel Consumed Expense,

(including NOX emission allowance expense) is taken from Mr. DiGaetano’s

Exhibit No. A-11 (SMD-2). The Cost of Industrial Send Out Steam Sales, as

reported in the Monthly Reports of Power Supply Cost, is subtracted from the

total booked cost to obtain the cost of fuel consumed for electric generation.

Q. Do your calculations include the expense for oxides of nitrogen (NOX)

emission allowances?

A. Yes. The November 23, 2004 Order in Case No. U-13808 approved the

Company’s request to recognize the cost of NOX emission allowances as an

integral part of the cost of power supply. (MPSC Order in Case No. U-13808

dated November 23, 2004, p. 112) Because NOX emission allowances must

be secured in order to burn the fuel required to operate the Company’s power

plants, and are utilized or “used up” in the process of burning the fuel, they are

considered to be a booked cost of fuel burned for electric generation. Edison

Witness Mr. James Byron further supports NOX emission allowance expense

in his testimony.

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Q. Do your calculations include transmission expense in the PSCR?

A. Yes. Commencing with the Commission’s November 23, 2004 Final Order in

Case No. U-13808, transmission and energy market related services provided

by the Midwest Independent System Operator (MISO) and International

Transmission Company (ITC) are authorized to be recovered through the

PSCR. Detroit Edison pays for its network transmission associated services

based on the rates approved by the Federal Energy Regulatory Commission

(FERC) for transmission services provided by the International Transmission

Company (ITC) and MISO.

Q. What is the Transmission expense shown on Exhibit No. A-16 (KLO-1)?

A. In accordance with the Case No. U-13808 Final Order dated November 23,

2004; Transmission Expense on this Exhibit reflects only the expense incurred

by Detroit Edison for the period November 24, 2004 through December 31,

2004. Both Net Transmission Expense and Deferred Transmission Expense

are taken from Exhibit No. A-14 (SMD-5). Total Transmission Expense shown

on Line 5 is used for reconciliation of costs for customers taking service on

uncapped rates. A lower amount, Net Transmission Expense, which excludes

the Deferred Transmission Expense shown on Line 6, is used for reconciliation

of costs for rate classes that are subject to rate caps. Deferred Transmission

Expense includes two components of transmission expense (MISO Schedule

10 and MISO Schedule 18) that the MPSC has ruled are eligible to be deferred

until after the rate caps have expired. (Case No. U-13808 Final Order, dated

November 23, 2004 p. 67)

KLO - 8


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Q. Does the Transmission Expense included on Exhibit No. A-16 (KLO-1)

represent all of the transmission expense incurred by the Company

during the November 24 through December 31, 2004 time period?

A. No. As testified to by Mr. DiGaetano, payments for point-to-point service

provided under MISO Schedules 7 and 8 were included in Purchased Power.

Further, both the expense incurred and the revenue received by Detroit Edison

for providing ancillary services under MISO Schedules 2, 3, 5 and 6 are

included in Detroit Edison’s base rates.

Q. What is the source of the sales and expenses of Direct Assignment

Customers on Exhibit No. A-16 (KLO-1)?

A. The sales and expenses shown on Lines 10 though 26 associated with the

Special Manufacturing Contracts (SMC), Large Customer Contracts (LCC),

Rates D8 and LCC8 in the buyout mode, Rate R10, and FERC Interruptible

customers are developed from the Company’s billing records.

Q. Can you explain the calculation of Adjusted Purchased Power Expense

on Exhibit No. A-16 (KLO-1)?

A. Yes, the calculation of Adjusted Purchased Power Expense is shown on Lines

28 through 43. Adjusted Purchased Power Expense is Purchased Power

Expense less the Third Party Wholesale Power Sales Fuel Cost, Third Party

Wholesale Power Sales Credit, and Energy Imbalance Fuel Cost.

Q. What is the source of each of the components of Adjusted Purchased

Power Expense on Exhibit No. A-16 (KLO-1)?

KLO - 9


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A. The booked cost of Purchased Power Expense is taken from Mr. DiGaetano’s

Exhibit No. A-10 (SMD-1). Third Party Wholesale Power Sales Fuel Cost and

Energy Imbalance Fuel Cost are taken from Mr. Byron’s Exhibit No. A-7 (JHB-

7). As discussed by Mr. Harvill, and calculated by Mr. Sadagopan, the Third

Party Wholesale Sales Credit is 75.7% of the Third Party Wholesale Power

Sales Net Proceeds.

Q. How was Third Party Wholesale Power Sales Net Proceeds calculated?

A. Third Party Wholesale Power Sales Net Proceeds are Third Party Wholesale

Power Sales Revenue (excluding Energy Imbalance) less Third Party

Wholesale Power Sales Fuel Cost and Third Party Wholesale Power

Production O&M Cost. As more fully described by Detroit Edison witness Mr.

Harvill, the Company has used approximately 76% of the net proceeds from

third party wholesale power sales as a PSCR offset. Other than the calculation

values described above, Mr. Byron’s Exhibit No. A-7 (JHB-7) is the source of

the annual revenues and costs of Third Party Wholesale Power Sales. I am

responsible for the distribution of the monthly Third Party Wholesale Power

Sales values as they are used in the calculation of the monthly over (under)

recovery of PSCR revenue.

Q. Did the Company include the expense associated with SO2 emission

allowances in the 2004 PSCR Reconciliation?

A. No. Although SO2 emission allowances were included in the 45-day Reports,

they were removed from the instant reconciliation in accordance with the

Commission’s November 23, 2004 Order in Case No. U-13808.

KLO - 10


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Q. Were there any revisions to the Commission authorized PSCR base or

loss factor during 2004?

A. Yes. In its Final Order in Case No. U-13808, the Commission authorized a

change in the PSCR base to $0.01732 at the generation level and a reduction

in the loss factor from 7.8% to 7.2%. In addition, the PSCR factor was reset to

zero. My calculations utilize these changes.

Q. What PSCR factor did Detroit Edison apply to the bills of customers

taking electric service on Residential Rates during the period January 1,

2004 through February 20, 2004?

A. During the January 1, 2004 through February 20, 2004 period, Residential

customer bills reflected a PSCR factor of 1.94 mills/kWh. Pursuant to the

Commission’s February 20, 2004 “Interim Order” in Case No. U-13808,

Residential customer bills reflected a credit PSCR factor of 1.05 mills/kWh,

effective February 21, 2004.

Q. For the January 1, 2004 through February 20, 2004 period, what PSCR

factor was used in the calculation of revenues in determining the PSCR

over (under) recovery?

A. A PSCR factor of 2.04 mills/kWh was used to calculate the PSCR revenues for

all PSCR customers during the January 1 through February 20, 2004 time

period. The basis for not using a different PSCR factor for the Residential

Rate Class customers was Detroit Edison’s interpretation of the Commission’s

2001 order in Case No. U-12478, the Securitization Case. In its order

implementing PA 141, the Commission directed the Company to implement a

KLO - 11


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5% rate reduction to all rate components of Residential Rate Class bills. This

rate reduction was later funded by Securitization. Because savings from

securitization fund the 5% rate reduction, Edison was effectively collecting at

the rate of 2.04 mills/kWh. Detroit Edison maintained the 5% rate reduction

and 1.94 mills/kWh factor for Residential customers until the Commission

established the PSCR billing factor of –1.05 mills/kWh in its Interim Order and

ordered refunds for billed PSCR factors in excess of -1.05 mills/kWh.

Subsequent to the Interim Order, the 5% rate reduction was maintained

through a lower rate increase surcharge; 2.99 mills/kWh versus 3.09

mills/kWh.

Q. Can you explain Exhibit No. A-17 (KLO-2).

A. Yes. Lines 1 through 14 show the calculation of the monthly PSCR allocation

factor. The PSCR allocation factor is the ratio of sales subject to the PSCR

clause, shown on Line 8, to Adjusted Total Sales shown on Line 12.

Lines 16 through 20 show the calculation of recoverable PSCR expense from

the figures shown on Exhibit No. A-16 (KLO-1) before the adjustment for

SMC/LCC cogenerators.

Q. What is the SMC/LCC cogenerator adjustment to booked power supply

expense for the 2004 PSCR reconciliation period?

A. Line 22 shows a reduction to total electric booked power supply expense for

the total electric SMC/LCC cogenerator adjustment discussed in the direct

testimony of Company witness Mr. Byron. This adjustment reflects the

KLO - 12


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incremental increase in firm load from the load previously served by the Ford

Rawsonville, Hospitals (Beaumont, Grace, Hutzel) and GM Pontiac

cogenerators. This adjustment was evenly distributed throughout 2004.

Lines 27 through 29 show the calculation of recoverable transmission expense.

Transmission expense is allocated based on the ratio of PSCR Transmission

Sales to Net Adjusted Transmission Sales. The PSCR Transmission

Allocation Factor accounts for the fact that Detroit Edison purchases

transmission service for some customers that are not subject to the PSCR

clause, i.e., the City of Detroit’s Public Lighting Department, unmetered sales,

etc.

Q. Does the Company receive any revenue for transmission related ancillary

services?

A. Yes. Detroit Edison provides ancillary services, schedules 2, 3, 5 and 6 in

accordance with its FERC-approved ancillary service tariff. These revenues

are reported in the FERC Form 1 and MPSC Form P-521, on page 331B,

Other Electric Revenues, Transmission Services. In MPSC Case No. U-

13808, these revenues were included in Total Revenues, line 1, as

Miscellaneous Revenues, (reference Case No. U-13808, Exhibit No. A-15,

Schedule C-1), and therefore have already been credited in base rates.

Q. What else does Exhibit No. A-17 (KLO-2) show?

A. Line 25 shows the Applicable Power Supply Energy Expense after applying the

PSCR Allocation Factor to Net Power Supply Expense shown on Line 23.

KLO - 13


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Line 31 shows the total Applicable Power Supply Expense. It is the sum of

Applicable Power Supply Energy Expense plus Applicable PSCR Transmission

Expense.

Lines 33 through 42 show the calculation of PSCR revenues. Line 44 shows

the over (under) recovery before interest charges and before recognition of the

refund ordered by the Commission in its Interim Order. At year-end 2004,

before interest and the Interim Order PSCR Refund, the Company was over-

recovered by $23,812,193 for customers not subject to rate caps during the

2004 PSCR reconciliation period.

Line 54 shows the cumulative monthly over (under) recoveries after

subtracting the Interim Order PSCR Refund principal and interest. The over-

recovery for customers not subject to rate caps at year-end 2004 is

$7,689,671, which includes interest of $793,692.

Q. Can you explain the treatment of the U-13808 Interim Order PSCR

refund?

A. Yes. In its Interim Order, the MPSC ordered PSCR factor refunds on a

historical basis of all power supply cost recovery amounts collected above

–1.05 mills/kWh from January 1, 2004 to February 21, 2004, with interest at

11%. The principal amount of the refund as shown on Line 46 was

$16,481,422 and the interest amount shown on line 52 was $434,792. The

refund amount was determined for each customer based on their historical

kWh consumption.

KLO - 14


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Q. What is the purpose of Exhibit No. A-18 (KLO-3)?

A. This Exhibit shows the calculation of the adjustment for capped customers due

to the deferred transmission expense. The adjustment is carried over to

Exhibit A-20 to calculate the PSCR refund factor for capped customers.

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Q. Can you explain why the 45-day Reports submitted to the Commission

show a different under-recovery for PSCR purposes during 2004, than

your Exhibits?

A. Yes. Absent specific Commission direction regarding the treatment of third

party wholesale power sales revenue as it impacts recoverable PSCR

expense, the Company presented 45-day Report information consistent with

the format used in prior years. This was reasonable because the Company

could not accurately anticipate what changes would be required by the Final

Order in MPSC Case No. U-13808.

Q. Can you explain Exhibit No. A-19 (KLO-4)?

A. Yes. Exhibit No. A-19 (KLO-4) presents an example of how the PSCR refund

factor should be developed for the Uncapped Customer classes depending on

the month the Commission issues its order for refund. Column (a) and Column

(b) show the interest calculation for various months in 2005 and 2006 based

on the year-end 2004 over-recovered balance. Interest is calculated using the

Company’s authorized return on common equity to the midpoint of the billing

month. Interest for the various months in 2006 is calculated assuming annual

compounding of interest as of year-end 2005.

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The exhibit illustrates five possible PSCR reconciliation factor scenarios that

could occur in calendar year 2005 and 2006. For example, if an order was

issued in this case in early October, in time to be applied to November 2005

bills, the Company would apply the credit billing factor developed on Line 4 to

bills rendered in November 2005. Likewise, if an order was issued in this case

in time for December 2005 bills, the credit billing factor developed on Line 9

would be applied to bills rendered in December 2005. If in time for the January

2006 bills, the credit billing factor developed on Line 14 would be applied to

bills rendered in January 2006, and so on.

Column (c) shows the over-recovery principal amount at year-end 2004.

Column (d) shows the total over-recovery including interest. It is the sum of

Column (b) and Column (c).

Column (f) shows estimated monthly sales for which this credit PSCR

reconciliation-billing factor applies. The PSCR reconciliation-billing factor will

be applied prospectively.

Q. Would you please explain Exhibit No. A-20 (KLO-5)?

A. Yes. Exhibit No. A-20 (KLO-5) presents an example of how the refund factor

should be developed for the Capped Customer classes depending on the

month the Commission issues its order for refund. Similar to Exhibit No. A-19

(KLO-4), Columns (a) through (g) show the calculation of interest on the

additional over-recovery of $417,596 for Capped Customer Classes resulting

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from deferring a portion of transmission expense. The calculation of a separate

factor was necessary because the Capped Customer sales base is only

41.06% of the total sales base and the additional over-recovery amount needs

to be only refunded to those specific classes of customers.

Column (g) shows the Deferred Transmission factor that will be incorporated

into the refund.

When the Commission issues its order in this proceeding, the Company will

refund the total PSCR reconciliation over-recovery for customers whose rates

are capped by adding the Deferred Transmission Factor shown in column (g)

to the PSCR Reconciliation factor shown in column (h) and apply the resulting

credit billing factor to sales in the month prior to the billing month. Column (i)

shows the combined Reconciliation and Deferred Transmission Factor.


A. Yes.

KLO - 17




EXHIBITS

OF

KEVIN L. O’NEILL

MPSC Case No. U-_______Exhibit No. A-16 (KLO-1)

Page 1 of 2Detroit Edison Company2004 PSCR ReconciliationPower Supply Expenses and Direct Assignments

LineNo. January February March April May June

-1 Electric Department Fuel Consumed Expense (including NOx) 57,028,108$ 50,240,361$ 50,039,937$ 42,196,278$ 44,600,075$ 51,484,652$ 2 Cost of Steam Sales 255,975$ 215,027$ 208,483$ 190,707$ 132,094$ 134,577$ 3 Fuel Costs for Electric Generation 56,772,133$ 50,025,334$ 49,831,453$ 42,005,572$ 44,467,981$ 51,617,566$ 45 Total Transmission Expense - Uncapped6 Deferred Transmission Expense7 Net Transmission Expense - Capped8910 Expenses of R10 1,542,114$ 1,066,928$ 1,296,579$ 1,332,160$ 1,967,482$ 1,621,430$ 11 Expenses of D8 in the Buyout Mode -$ -$ -$ -$ -$ 18,378$ 12 Expenses of LCC8 in the Buyout Mode -$ -$ -$ -$ -$ 2,978$ 13 Cost Attributable to SMC Interruptible Sales 182,682$ 130,330$ 171,304$ 168,754$ 316,853$ 396,406$ 14 Cost Attributable to LCC10 Interruptible Sales 298,401$ 218,380$ 302,661$ 288,707$ 597,300$ 554,237$ 15 Cost Attributable to FERC Interruptible Sales 409,529$ 290,263$ 263,782$ 288,395$ 481,257$ 446,250$ 16 D8/LCC Special Buy-Out Related Charges -$ -$ -$ -$ -$ 2,139$ 17 R10 (incl. SMC & LCC) Option Premium & Transmission Charges -$ -$ -$ -$ -$ 33,593$ 18 Total Expenses of Direct Assignment Customers 2,432,726$ 1,705,901$ 2,034,326$ 2,078,016$ 3,362,891$ 3,075,411$ 1920 R10 Sales kWh 75,408,037 70,879,894 72,302,494 74,684,810 71,055,146 64,066,387 21 D8 Sales in the Buyout Mode kWh - - - - - 223,868 22 LCC8 Sales in the Buyout Mode kWh - - - - - 36,280 23 SMC Interruptible Sales kWh 7,497,015 8,315,313 8,858,955 7,980,437 9,679,577 12,710,606 24 LCC10 Interruptible Sales kWh 13,972,109 14,076,817 15,994,709 14,113,075 16,154,225 17,108,340 25 FERC Interruptible Sales kWh 16,220,519 13,770,389 12,106,881 11,971,355 12,503,491 11,938,178 26 Total Sales of Direct Assignment Customers kWh 113,097,680 107,042,413 109,263,039 108,749,677 109,392,439 106,083,6592728 Purchased Power Expense 14,754,299$ 12,656,132$ 13,976,333$ 10,207,888$ 13,154,851$ 18,224,757$ 2930 Third Party Sales (excl. energy imbalance) MWh 527,216 470,385 569,411 404,566 237,219 344,2933132 Third Party Wholesale Power Sales Revenue (excl. energy imbalance) 19,761,318$ 17,500,925$ 19,897,204$ 14,252,741$ 8,352,774$ 14,259,325$ 33 Third Party Wholesale Power Sales Fuel Cost 7,864,296$ 7,016,566$ 8,493,709$ 6,034,772$ 3,538,515$ 5,135,701$ 34 Third Party Wholesale Prod O&M Cost 6,374,038$ 5,686,950$ 6,884,179$ 4,891,203$ 2,867,978$ 4,162,502$ 35 Third Party Wholesale Power Sales Net Proceeds 5,522,985$ 4,797,409$ 4,519,316$ 3,326,766$ 1,946,281$ 4,961,122$ 3637 Third Party Wholesale Power Sales Net Proceeds Credit 4,180,802$ 3,631,554$ 3,421,042$ 2,518,303$ 1,473,301$ 3,755,481$ 3839 Energy Imbalance Sales MWh 30,402 16,139 16,094 10,265 13,416 15,81440 Energy Imbalance Fuel Cost 453,502$ 240,740$ 240,069$ 153,119$ 200,122$ 235,892$ 41 Energy Imbalance Revenue 2,444,899$ 1,060,706$ 1,039,757$ 744,970$ 925,957$ 1,078,392$ 4243 Adjusted Purchase Power Expense 2,255,699$ 1,767,272$ 1,821,513$ 1,501,693$ 7,942,914$ 9,097,683$


Page 2 of 2Detroit Edison Company2004 PSCR ReconciliationPower Supply Expenses and Direct Assignments

LineNo.

-1 Electric Department Fuel Consumed Expense (including NOx)2 Cost of Steam Sales3 Fuel Costs for Electric Generation45 Total Transmission Expense - Uncapped6 Deferred Transmission Expense7 Net Transmission Expense - Capped8910 Expenses of R1011 Expenses of D8 in the Buyout Mode12 Expenses of LCC8 in the Buyout Mode13 Cost Attributable to SMC Interruptible Sales14 Cost Attributable to LCC10 Interruptible Sales15 Cost Attributable to FERC Interruptible Sales16 D8/LCC Special Buy-Out Related Charges17 R10 (incl. SMC & LCC) Option Premium & Transmission Charges18 Total Expenses of Direct Assignment Customers1920 R10 Sales kWh21 D8 Sales in the Buyout Mode kWh22 LCC8 Sales in the Buyout Mode kWh23 SMC Interruptible Sales kWh24 LCC10 Interruptible Sales kWh25 FERC Interruptible Sales kWh26 Total Sales of Direct Assignment Customers kWh2728 Purchased Power Expense2930 Third Party Sales (excl. energy imbalance) MWh3132 Third Party Wholesale Power Sales Revenue (excl. energy imbalance)33 Third Party Wholesale Power Sales Fuel Cost34 Third Party Wholesale Prod O&M Cost35 Third Party Wholesale Power Sales Net Proceeds3637 Third Party Wholesale Power Sales Net Proceeds Credit3839 Energy Imbalance Sales MWh40 Energy Imbalance Fuel Cost41 Energy Imbalance Revenue4243 Adjusted Purchase Power Expense

July August September October November December Totals

56,312,854$ 55,135,441$ 53,451,189$ 50,502,579$ 52,478,413$ 56,852,573$ 620,322,460$ 115,874$ 127,728$ 83,451$ 145,349$ 144,074$ 157,729$ 1,911,067$

56,458,260$ 55,396,899$ 53,675,953$ 50,366,985$ 52,334,789$ 56,708,024$ 619,660,948$

1,541,840$ 8,467,384$ 10,009,224$ 66,156$ 347,646$ 413,803$

1,475,683$ 8,119,738$ 9,595,422$

1,605,874$ 1,664,065$ 1,517,362$ 1,108,961$ 1,277,552$ 1,186,000$ 17,186,506$ -$ -$ -$ -$ -$ -$ 18,378$ -$ -$ -$ -$ -$ -$ 2,978$

242,608$ 332,091$ 241,288$ 121,034$ 144,517$ 121,087$ 2,568,955$ 297,499$ 405,923$ 335,407$ 229,864$ 303,819$ 217,507$ 4,049,705$ 347,205$ 401,744$ 369,711$ 225,018$ 376,030$ 389,909$ 4,289,091$

-$ -$ -$ -$ -$ -$ 2,139$ 24,893$ 30,322$ -$ -$ -$ -$ 88,807$

2,518,080$ 2,834,145$ 2,463,768$ 1,684,877$ 2,101,918$ 1,914,501$ 28,206,561

74,941,013 80,306,565 79,654,610 74,612,931 64,877,677 71,380,257 874,169,821 - - - - - - 223,868 - - - - - - 36,280

9,303,009 11,564,327 11,297,307 7,997,299 6,332,758 6,724,357 108,260,960 13,500,702 15,439,736 14,945,986 14,189,838 13,587,683 11,540,001 174,623,221 10,398,420 11,186,055 11,747,928 10,794,277 13,210,802 15,316,639 151,164,934

108,143,144 118,496,683 117,645,831 107,594,345 98,008,920 104,961,254 1,308,479,084

15,872,358$ 19,428,876$ 16,276,385$ 10,071,125$ 9,742,617$ 17,590,581$ 171,956,202$

457,464 387,370 468,609 839,708 560,151 817,481 6,083,872

17,101,062$ 14,305,133$ 16,696,302$ 26,445,109$ 18,600,451$ 30,464,469$ 217,636,813$ 6,823,834$ 5,778,266$ 6,990,080$ 12,525,641$ 8,355,580$ 12,194,078$ 90,751,036$ 5,530,740$ 4,683,303$ 5,665,483$ 10,152,073$ 6,772,226$ 9,883,340$ 73,554,015$ 4,746,488$ 3,843,564$ 4,040,739$ 3,767,395$ 3,472,645$ 8,387,050$ 53,331,761$

3,593,008$ 2,909,510$ 3,058,768$ 2,851,851$ 2,628,731$ 6,348,849$ 40,371,201$

29,662 64,351 35,045 24,222 14,644 18,029 288,084442,458$ 959,907$ 522,754$ 361,316$ 218,441$ 268,932$ 4,297,252$

2,420,242$ 4,576,225$ 2,991,471$ 2,183,735$ 1,176,166$ 5,926,597$ 26,569,118.04

5,013,058$ 9,781,194$ 5,704,783$ (5,667,683)$ (1,460,136)$ (1,221,278)$ 36,536,713$

MPSC Case No. U-______Exhibit No. A-17 (KLO-2)

Page 1 of 2

Detroit Edison Company2004 PSCR Reconciliation Monthly Over (Under) Recovery Uncapped Customers

LineNo. January February March April May June July

1 Total System Sales kWh 3,764,963,223 3,519,045,251 3,695,393,219 3,273,454,016 3,444,118,212 3,269,275,916 3,808,912,8092 Adjustment for LCC, SMC, R10 kWh (78,292,835) (72,903,704) 71,377,501 10,304,712 29,639,446 (60,353,920) 95,039,8963 Adjusted Sales kWh 3,686,670,388 3,446,141,547 3,766,770,720 3,283,758,728 3,473,757,658 3,208,921,996 3,903,952,70545 Less: Unmetered kWh 38,244,692 36,171,276 34,359,514 31,347,937 29,015,028 27,459,949 28,411,9716 Less: Resale kWh 194,092,164 176,617,497 185,166,358 180,852,525 185,939,008 185,944,283 181,500,1707 Less: Total Sales of Direct Assignment Customers 113,097,680 107,042,413 109,263,039 108,749,677 109,392,439 106,083,659 108,143,144 8 PSCR Sales kWh 3,357,456,371 3,140,080,750 3,450,088,690 2,974,779,944 3,161,914,674 2,901,372,283 3,596,295,840910 Adjusted Sales kWh 3,686,670,388 3,446,141,547 3,766,770,720 3,283,758,728 3,473,757,658 3,208,921,996 3,903,952,70511 Less: Total Sales of Direct Assignment Customers kWh 113,097,680 107,042,413 109,263,039 108,749,677 109,392,439 106,083,659 108,143,14412 Adjusted Total Sales kWh 3,573,572,708 3,339,099,134 3,657,507,681 3,175,009,051 3,364,365,219 3,102,838,337 3,795,809,5611314 PSCR Allocation Factor 0.9395 0.9404 0.9433 0.9369 0.9398 0.9351 0.94741516 Fuel Costs for Electric Generation 56,772,133$ 50,025,334$ 49,831,453$ 42,005,572$ 44,467,981$ 51,617,566$ 56,458,260$ 17 Adjusted Purchased Power Expense 2,255,699$ 1,767,272$ 1,821,513$ 1,501,693$ 7,942,914$ 9,097,683$ 5,013,058$ 18 Total Power Supply Expenses 59,027,832$ 51,792,606$ 51,652,967$ 43,507,265$ 52,410,895$ 60,715,248$ 61,471,319$ 19 2,432,726$ 1,705,901$ 2,034,326$ 2,078,016$ 3,362,891$ 3,075,411$ 2,518,080$ 20 Net Power Supply Expense (pre-adjustment) 56,595,106$ 50,086,705$ 49,618,641$ 41,429,249$ 49,048,004$ 57,639,837$ 58,953,239$ 2122 Less: SMC/LCC Cogenerator Adjustment 121,833$ 121,833$ 121,833$ 121,833$ 121,833$ 121,833$ 121,833$ 23 Net Power Supply Expense 56,473,273$ 49,964,872$ 49,496,807$ 41,307,415$ 48,926,171$ 57,518,004$ 58,831,406$ 2425 Applicable PSCR Energy Expense 53,056,640$ 46,986,965$ 46,690,338$ 38,700,917$ 45,980,815$ 53,785,086$ 55,736,874$ 2627 Transmission Expense -$ -$ -$ -$ -$ -$ -$ 28 PSCR Transmission Allocation Factor29 Applicable PSCR Transmission Expense -$ -$ -$ -$ -$ -$ -$ 3031 Total Applicable PSCR Expense 53,056,640$ 46,986,965$ 46,690,338$ 38,700,917$ 45,980,815$ 53,785,086$ 55,736,874$ 3233 Base Cost Mills/kWh 15.49 15.49 15.49 15.49 15.49 15.49 15.49 34 Loss Multiplier 1.078 1.078 1.078 1.078 1.078 1.078 1.078 35 Base Cost including Multiplier Mills/kWh 16.69822 16.69822 16.69822 16.69822 16.69822 16.69822 16.69822 36 PSCR Sales kWh 3,357,456,371 3,140,080,750 3,450,088,690 2,974,779,944 3,161,914,674 2,901,372,283 3,596,295,84037 Base Power Supply Revenues 56,063,545$ 52,433,759$ 57,610,340$ 49,673,530$ 52,798,347$ 48,447,753$ 60,051,739$ 3839 PSCR Factor Mills/kWh 2.04 0.82 (1.05) (1.05) (1.05) (1.05) (1.05)40 PSCR Revenues 6,505,024$ (4,012,196)$ (3,622,593)$ (3,123,519)$ (3,320,010)$ (3,046,441)$ (3,776,111)$ 41 42 Total Revenues 62,568,570$ 48,421,563$ 53,987,747$ 46,550,011$ 49,478,336$ 45,401,312$ 56,275,628$ 4344 Monthly Over (Under) Recovery 9,511,930$ 1,434,598$ 7,297,408$ 7,849,094$ 3,497,521$ (8,383,774)$ 538,755$ 45 Over (Under) Recovery Beginning Balance -$ 9,511,930$ 10,946,528$ 18,243,936$ 13,382,696$ 13,109,129$ 4,725,355$ 46 U-13808 PSCR Refund -$ -$ -$ 12,710,334$ 3,771,088$ -$ -$ 47 Over (Under) Recovery Ending Balance 9,511,930$ 10,946,528$ 18,243,936$ 13,382,696$ 13,109,129$ 4,725,355$ 5,264,110$ 48 Over (Under) Recovery Average Balance 4,755,965$ 10,229,229$ 14,595,232$ 15,813,316$ 13,245,912$ 8,917,242$ 4,994,732$ 49 Annual Interest Rate 11.0000% 11.0000% 11.0000% 11.0000% 11.0000% 11.0000% 11.0000%50 Monthly Interest Rate 0.009167 0.009167 0.009167 0.009167 0.009167 0.009167 0.00916751 Interest 43,598$ 93,771$ 133,794$ 144,961$ 121,425$ 81,744$ 45,787$ 52 U-13808 PSCR Interest Refund -$ -$ -$ 317,384$ 117,408$ -$ -$ 5354 Cumulative Over (Under) Recovery 9,555,528$ 11,083,897$ 18,515,100$ 13,481,436$ 13,211,887$ 4,909,857$ 5,494,399$ 555657

Less: Total Expenses of Direct Assignment Customers

MPSC Case No. U-______Exhibit No. A-17 (KLO-2)

Page 2 of 2

Detroit Edison Company2004 PSCR Reconciliation Monthly Over (Under) Recovery Uncapped Customers

LineNo.

1 Total System Sales kWh2 Adjustment for LCC, SMC, R10 kWh3 Adjusted Sales kWh45 Less: Unmetered kWh6 Less: Resale kWh7 Less: Total Sales of Direct Assignment Customers8 PSCR Sales kWh910 Adjusted Sales kWh11 Less: Total Sales of Direct Assignment Customers kWh12 Adjusted Total Sales kWh1314 PSCR Allocation Factor1516 Fuel Costs for Electric Generation17 Adjusted Purchased Power Expense18 Total Power Supply Expenses1920 Net Power Supply Expense (pre-adjustment)2122 Less: SMC/LCC Cogenerator Adjustment23 Net Power Supply Expense2425 Applicable PSCR Energy Expense2627 Transmission Expense28 PSCR Transmission Allocation Factor29 Applicable PSCR Transmission Expense3031 Total Applicable PSCR Expense3233 Base Cost Mills/kWh34 Loss Multiplier35 Base Cost including Multiplier Mills/kWh36 PSCR Sales kWh37 Base Power Supply Revenues3839 PSCR Factor Mills/kWh40 PSCR Revenues4142 Total Revenues4344 Monthly Over (Under) Recovery45 Over (Under) Recovery Beginning Balance46 U-13808 PSCR Refund 47 Over (Under) Recovery Ending Balance48 Over (Under) Recovery Average Balance49 Annual Interest Rate50 Monthly Interest Rate51 Interest52 U-13808 PSCR Interest Refund5354 Cumulative Over (Under) Recovery555657

Less: Total Expenses of Direct Assignment Customers

August September October November December Total

3,790,418,599 3,554,776,553 3,405,410,923 3,361,559,351 3,688,698,042 42,576,026,114(191,413,973) 42,865,773 (95,590,929) 79,864,241 644,881 (168,818,911)

3,599,004,626 3,597,642,326 3,309,819,994 3,441,423,592 3,689,342,923 42,407,207,203

30,488,995 32,432,089 35,568,524 37,078,045 39,160,488 399,738,508180,825,258 169,111,609 184,848,323 181,205,275 191,087,905 2,197,190,375118,496,683 117,645,831 107,594,345 98,008,920 104,961,254 1,308,479,084

3,280,379,745 3,290,200,725 2,992,603,079 3,138,342,154 3,369,449,915 38,653,000,450

3,599,004,626 3,597,642,326 3,309,819,994 3,441,423,592 3,689,342,923 42,407,207,203118,496,683 117,645,831 107,594,345 98,008,920 104,961,254 1,308,479,084

3,480,507,943 3,479,996,495 3,202,225,649 3,343,414,672 3,584,381,669 41,098,728,119

0.9425 0.9455 0.9345 0.9387 0.9400 0.9405

55,396,899$ 53,675,953$ 50,366,985$ 52,334,789$ 56,708,024$ 619,660,948$ 9,781,194$ 5,704,783$ (5,667,683)$ (1,460,136)$ (1,221,278)$ 36,536,713$

65,178,092$ 59,380,736$ 44,699,302$ 50,874,654$ 55,486,746$ 656,197,661$ 2,834,145$ 2,463,768$ 1,684,877$ 2,101,918$ 1,914,501$ 28,206,561$

62,343,947$ 56,916,967$ 43,014,425$ 48,772,736$ 53,572,244$ 627,991,100$

121,833$ 121,833$ 121,833$ 121,833$ 121,833$ 1,462,000$ 62,222,114$ 56,795,134$ 42,892,592$ 48,650,902$ 53,450,411$ 626,529,100$

58,644,342$ 53,699,799$ 40,083,127$ 45,668,602$ 50,243,386$ 589,276,892$

-$ -$ -$ 1,541,840$ 8,467,384$ 10,009,224$ 0.9575 0.9577

-$ -$ -$ 1,476,312$ 8,109,214$ 9,585,526$

58,644,342$ 53,699,799$ 40,083,127$ 47,144,914$ 58,352,600$ 598,862,418$

15.49 15.49 15.49 1.078 1.078 1.078

16.69822 16.69822 16.69822 17.55976 18.40968 3,280,379,745 3,290,200,725 2,992,603,079 3,138,342,154 3,369,449,915 38,652,964,170

54,776,503$ 54,940,496$ 49,971,145$ 55,108,522$ 62,030,488$ 653,906,166$

(1.05) (1.05) (1.05) (1.02) (0.30)(3,444,399)$ (3,454,711)$ (3,142,233)$ (1,776,127)$ (5,018,240)$ (31,231,556)$

51,332,104$ 51,485,785$ 46,828,911$ 53,332,395$ 57,012,248$ 622,674,611$

(7,312,238)$ (2,214,014)$ 6,745,784$ 6,187,481$ (1,340,352)$ 23,812,193$ 5,264,110$ (2,048,129)$ (4,262,143)$ 2,483,641$ 8,671,123$

-$ -$ -$ -$ -$ 16,481,422$ (2,048,129)$ (4,262,143)$ 2,483,641$ 8,671,123$ 7,330,771$ 7,330,771$ 1,607,991$ (3,155,136)$ (889,251)$ 5,577,382$ 8,000,947$ 11.0000% 3.3613% 2.3806% 11.0000% 11.0000%0.009167 0.002801 0.001984 0.009167 0.009167

14,740$ (8,838)$ (1,764)$ 51,128$ 73,345$ 793,692$ -$ -$ -$ -$ -$ 434,792$

(1,803,099)$ (4,025,951)$ 2,718,069$ 8,956,678$ 7,689,671$ 7,689,671$

Note 1: December billed sales computed using -0.30 Mills/kWh and unbilled sales computed using -2.00 Mills/kWh.

MPSC Case No. U-_____Exhibit A-18 (KLO-3)

Page 1 of 1Detroit Edison Company2004 PSCR Reconciliation Monthly Over (Under) Recovery Adjustment for Capped Customers

LineNo. November December Total

1 Deferred Transmisson Expense 66,156$ 347,646$ 413,803$ 23 Monthly Interest Rate 0.009167 0.00916745 Interest 606$ 3,187$ 3,793$ 67 Total Adjustment 66,763 350,833 417,596

MPSC Case No. U-_______

Exhibit No. A-19 (KLO-4)Page 1 of 1 Detroit Edison Company

2004 PSCR ReconciliationCalculation of Billing Factors - Uncapped Customers

(a) (b) (c) (d) (e) (f) (g)

Interest Calculation on year-end 2004 Reconciliation Reconciliation Estimated 2004 PSCROver - Recovery Over - Over - Total 2004 Monthly Reconciliation

($) Recovery Recovery Over - PSCR Sales FactorLine Interest Principal Recovery Refund MWH Mills/kWhNo. (Note 1/Note 2) ($) ($) ($) Month (Note 3) (d) / (f)

-------------------- -------------------------------------------------------------------------- -------------------- ------------------------------- ------------------- -------------- ------------------ --------------------123 $7,689,671 x 0.11 x 10.54 --------------------------------------------------------------------------= 740,131 + 7,689,671 = 8,429,802 Nov-05 3,366,140 (2.50)5 12678 $7,689,671 x 0.11 x 11.59 --------------------------------------------------------------------------= 810,619 + 7,689,671 = 8,500,290 Dec-05 3,618,060 (2.35)

10 12111213 $8,535,534 x 0.11 x 0.514 --------------------------------------------------------------------------= 39,121 + 8,535,535 = 8,574,656 Jan-06 3,780,680 (2.27)15 12161718 $8,535,534 x 0.11 x 1.519 --------------------------------------------------------------------------= 117,364 + 8,535,535 = 8,652,899 Feb-06 3,443,220 (2.51)20 12212223 $8,535,534 x 0.11 x 2.524 --------------------------------------------------------------------------= 195,606 + 8,535,535 = 8,731,141 Mar-06 3,636,860 (2.40)25 12262728293031 Note 1: Authorized Return on Equity = 11%32 Note 2: Interest in 2006 reflects annual compounding of interest for the year 2005. 33 : $7,689,671 x 0.11 = 845,864$ 3435 Note 3: Monthly Sales taken from the October 2004 Corporate Energy Forecast. Sales are adjusted36 using the 2004 PSCR sales factor = 38,653,000,450 / 41,098,728,119 = 0.9405

$7,689,671 + $845,864 = $8,535,535 at 12-31-2005


Page 1 of 1Detroit Edison Company2004 PSCR ReconciliationCalculation of Billing Factors - Capped Customers

(a) (b) (c) (d) (e) (f) (g) (h) (i)2004 PSCR 2004 Capped

Interest Calculation on year-end 2004 Reconciliation Reconciliation Estimated Deferred 2004 PSCR PSCR Transmission Over - Recovery Over - Over - Total 2004 Monthly Capped Transmission Reconciliation Reconciliation

($) Recovery Recovery Over - PSCR Sales Factor Factor FactorLine Interest Principal Recovery Refund MWH Mills/kWh Mills/kWh Mills/kWhNo. (Note 1/Note 2) ($) ($) ($) Month (Note 3) (d)/(f) (Note 4) (g) + (h)

-------------------- -------------------------------------------------------------------------- -------------------- ------------------------------- ------------------- -------------- ----------------------- -------------------- ---------------------- ---------------------123 $417,596 x 0.11 x 10.54 --------------------------------------------------------------------------= 40,194 + 417,596 = 457,790 Nov-05 1,382,137 (0.33) + (2.50) = (2.83)5 12678 $417,596 x 0.11 x 11.59 --------------------------------------------------------------------------= 44,022 + 417,596 = 461,618 Dec-05 1,485,575 (0.31) + (2.35) = (2.66)

10 12111213 $463,532 x 0.11 x 0.514 --------------------------------------------------------------------------= 2,358 + 463,532 = 465,890 Jan-06 1,552,347 (0.30) + (2.27) = (2.57)15 12161718 $463,532 x 0.11 x 1.519 --------------------------------------------------------------------------= 7,075 + 463,532 = 470,607 Feb-06 1,413,786 (0.33) + (2.51) = (2.84)20 12212223 $463,532 x 0.11 x 2.524 --------------------------------------------------------------------------= 11,791 + 463,532 = 475,323 Mar-06 1,493,295 (0.32) + (2.40) = (2.72)25 12262728293031 Note 1: Authorized Return on Equity = 11%32 Note 2: Interest in 2006 reflects annual compounding of interest for the year 2005. 33 : $417,596 x 0.11 = 45,936$ 3435 Note 3: Estimated Monthly PSCR Sales multiplied by .4106 which is the percentage of Residential & Small Commercial Sales to Total Electric Sales.36 Note 4: Source is Exhibit A-19 (KLO-4) Column (g).

$417,596 + $45,936 = $463,532 at 12-31-2005




QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

MARTIN L. HEISER

THE DETROIT EDISON COMPANY QUALIFICATIONS OF MARTIN L. HEISER

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Q. What is your name and business address, and by whom are you

employed?

A. My name is Martin L. Heiser. My business address is 2000 Second Ave.,

Detroit, Michigan 48226. I am employed by The Detroit Edison Company.

Q. What is your current position with Detroit Edison?

A. I am a Consultant, Regulatory Economics in the Pricing Department of the

Regulatory Policy and Operations Organization.


A. I graduated from the University of Michigan, Ann Arbor with a Bachelor of

Science Degree in Civil Engineering in 1981. In addition, I hold the degree of

Master of Business Administration with a concentration in Finance, from the

University of Michigan, Dearborn, which I received in 1991.

Q. Have you completed any other courses of study or attended any

professional seminars?

A. Yes, I have completed numerous professional-level training courses including

the Edison Electric Institute’s (“EEI”) Fundamental and Advanced Rate

courses, National Economic Research Associates’ Marginal Cost Methods, the

Financial Accounting Institute’s General Finance and Utility Finance &

Accounting for Financial Professionals courses, Depreciation Programs’ Basic

Depreciation Concepts course, EEI’s Transmission Pricing School, the

University of Chicago's seminar on Pricing Strategy and Tactics, and the

University of Wisconsin’s mini-course titled “The Wires Business.”

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Q. Do you belong to any professional organizations?

A. Yes, I am a member of the Engineering Society of Detroit.

Q. What is your employment history with Detroit Edison?

A. I joined Detroit Edison in 1985 as an Associate Engineer in the Project

Controls Department at the Fermi 2 Nuclear Power Plant. I was responsible

for tracking the engineering budget and measuring the effectiveness of

management programs.

I was promoted to Engineer in 1987 and performed various functions including

the scheduling of daily maintenance, forced outage, and refueling outage

activities.

In 1991, I was promoted to the position of Senior Cost Analyst, Cost of

Service, which was part of Revenue Requirement until February of 1993 when

the Cost of Service function was transferred to the Marketing & Sales

Organization. In 1994 my job was redefined as Pricing Analyst and included in

a new organization called Customer Energy Solutions. In March of 1998, I

returned to the Revenue Requirement Department and was promoted to

Principal Financial Analyst. In April of 2001, I joined the Pricing Department

and in November of 2002 was promoted to my current position.

Q. What are your responsibilities in your current position in the Pricing

Department?

A. I am responsible for performing cost of service studies, revenue requirement

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studies, economic analyses, depreciation studies, rate design and other short

and long-term financial evaluations. I am responsible for performing

embedded and marginal cost studies, and fully allocated class cost of service

studies.

Q. Have you had any involvement in ratemaking activities?

A. Yes. I have sponsored testimony before both the Michigan Public Service

Commission (“MPSC”) and the Federal Energy Regulatory Commission

(“FERC”). At FERC, I sponsored testimony and exhibits in Docket No. ER04-

14-000 regarding the costs associated with Ancillary Services under Detroit

Edison’s Ancillary Services Tariff (“DE AST”). I sponsored testimony and

exhibits in Docket No. ER00-3295-000 supporting the transmission related

revenue derived from Detroit Edison’s bundled retail rates. I supported

testimony and exhibits in Docket No. OA96-78-000 regarding the costs

associated with Detroit Edison’s Open Access Transmission Tariff (“DE

OATT”). In addition, I prepared portions of the cost of service study filed in

FERC Docket No. ER93-91-000 regarding a reduction in rates for Detroit

Edison’s wholesale for resale customers.

At the MPSC, I have sponsored testimony and exhibits in Case No. U-14399

regarding unbundling and realignment of rates, Case No. U-13350 regarding

net stranded costs, Case No. U-13286 regarding unbundling of rates, Case

No. U-11724 regarding accounting approval of depreciation practices for the

Ludington Pumped Storage Plant, and during the rebuttal phase of Case No.

U-11722 regarding general depreciation practices for Detroit Edison. In

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support of other witnesses, I helped prepare exhibits and workpapers for

Detroit Edison’s cost studies filed in the most recent general rate proceeding,

Case No. U-13808, as well as Detroit Edison’s prior general rate proceeding,

Case No. U-10102, experimental retail wheeling Case No. U-10176, and

Detroit Edison’s request for approval of a direct access tariff, Case No. U-

11452.

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THE DETROIT EDISON COMPANY DIRECT TESTIMONY OF MARTIN L. HEISER

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Q. What is the purpose of your direct testimony in this case?

A. The purpose of my direct testimony is threefold. First, I support the production

fixed cost “PFC” revenue percentage allocation factors that Mr. Sadagopan

used to calculate Detroit Edison’s PFC stranded costs for the year 2004.

These PFC percentage allocation factors are required for proper application of

the Staff’s method for calculating PFC stranded costs. Second, I support the

jurisdictional factors that Mr. Sadagopan used to calculate production fixed

costs. These factors are necessary because MPSC-approved stranded costs

apply only to sales and associated costs over which the MPSC has jurisdiction.

Third, I use the production operation and maintenance (“O&M”) expense and

jurisdictional revenue corresponding to the November 23, 2004 Order in MPSC

Case No. U-13808 (hereafter “Order” of “Final Order”) to calculate the

production O&M percentage of revenue that is used by Mr. Harvill to support

the reasonableness of the Company’s allocation of average 2004 production

O&M to third party wholesale power sales. Mr. Sadagopan uses the

production O&M percentage of revenue to determine the actual 2004 revenue

available to recover 2004 production O&M.



Exhibit No. A-21 (MLH-1) Production Fixed Cost Revenue Percentage,

Pre-Interim Order – 2004


Interim Order – 2004

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Final Order – 2004

Exhibit No. A-24 (MLH-4) Jurisdictional Factors for Production Fixed Costs

Exhibit No. A-25 (MLH-5) Production O&M Percentage of Order Revenue


A. Yes, they were.

Q. What method is being used to calculate stranded costs for 2004?

A. Staff method, as applied by the MPSC Staff in MPSC Case No. U-13808 to

calculate stranded costs for years 2002 and 2003, is being used to calculate

Detroit Edison’s PFC net stranded costs for 2004. The Commission accepted

the Staff’s calculation in its November 23, 2004 Order in Case No. U-13808.

The Staff’s method defines PFC net stranded costs as the difference between

actual PFC and revenue available to cover PFC. The Staff’s method is based

on the basic regulatory principle that rates are designed to collect revenue

equal to the approved full revenue requirement. Revenue available to cover

PFC is calculated by multiplying actual revenue from ultimate customers

(defined as Detroit Edison’s full service a/k/a bundled customers) by the PFC

revenue allocation percentage corresponding to Detroit Edison’s costs at the

time the rates were established.

Q. How is the PFC revenue allocation percentage calculated?

A. The PFC revenue allocation percentage is calculated by dividing the applicable

PFC by the applicable revenue. During the year 2004, there are three PFC

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revenue allocation percentages that correspond to the periods during which

different rates were in effect. Rates established in MPSC Case No. U-10102,

as modified by 2000 PA 141 and related Commission orders, were in effect

until the Interim Order in MPSC Case No. U-13808 was issued on February

20, 2004, (“Interim Order”). Rates established by the Interim Order remained

in effect until the Final Order in MPSC Case No. U-13808 was issued on

November 23, 2004, (“Final Order”).

Q. Do each of the periods you just described satisfy the basic regulatory

principle that rates are designed to collect revenue equal to the approved

full revenue requirement?

A. No. The Interim Order deferred some issues in the case until the Final Order

and therefore did not design interim rates to recover the Company’s full

revenue requirement. This situation required special consideration that I will

describe later in greater detail.

Q. How is the applicable PFC calculated?

A. Consistent with the Staff Method, PFC is calculated using selected

components of production revenue requirement. These components include

the pre-tax return on net production plant, depreciation expense, property

taxes and insurance.

Q. What principles does the Company follow in applying the Staff method to

calculate Detroit Edison’s PFC net stranded costs?

A. The first principle is matching. Adherence to this principle requires that Mr.

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Sadagopan’s Actual PFC revenue development matches that used to calculate

the Order PFC revenue allocation percentage. The second principle, single

application, requires that revenues can be used only once. Clearly, revenue

cannot be used to fund external funds and simultaneously be used to offset

Detroit Edison’s stranded costs. Funds dedicated to external funds include

Securitization, Nuclear Decommissioning, LIEEF, and minimum pension

funding. In addition, the fact that the PSCR clause was active during 2004

requires special consideration to ensure adherence to the single application

principle. The third principle, integrity, requires that the application fulfill the

intent of the Staff method. In order to ensure adherence to the integrity

principle, revenue from sources other than ultimate customers, such as

revenue from Electric Choice Customers, must be removed from both Order

and Actual revenue.

Q. Can you describe the approach you used to calculate the production

fixed cost revenue allocation percentage that applied prior to the

issuance of the Interim Order?

A. Yes. The PFC revenue allocation percentage for this period is shown on

Exhibit No. A-21 (MLH-1), “Production Fixed Cost Revenue Percentage, Pre-

Interim Order – 2004”. During this period, rates established in MPSC Case

No. U-10102, as modified by 2000 PA141 and related Commission orders,

were in effect. Therefore, I used as my starting point the PFC revenue

allocation percentage used by Staff to calculate PFC net stranded costs for

2002 and 2003 in MPSC Case No. U-13808.

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Q. Would it be appropriate to apply the Staff’s PFC revenue allocation

percentage to 2004 actual revenue collected prior to the issuance of the

Interim Order?

A. No, not without accounting for the fact that the Commission, in its order issued

December 18, 2003 in MPSC Case No. U-13808, reinstated the Power Supply

Cost Recovery “PSCR” clause effective January 1, 2004. Traditionally, under

an active PSCR clause, any over-collection of PSCR revenue is recorded as a

liability and returned to PSCR customers and any under-collection of PSCR

revenue is recorded as an asset and eventually recovered from PSCR

customers. This case is a departure from tradition because of the way

revenue from third party wholesale power sales potentially impact both PSCR

and PFC net stranded cost calculations. Clearly, any PSCR over-collection

due to revenue from third party wholesale power sales cannot be used twice;

once as a credit to PSCR customers’ bills and again as an offset to net

stranded costs.

Q. Given that the PSCR clause was active during 2004, what special

consideration have you given to fuel related costs?

A. As described by Mr. Harvill, net revenue from third party wholesale power

sales is being removed from the PFC net stranded cost calculation and set

aside for disposition by the Commission. This revenue can be used to offset

stranded costs, as a credit to the PSCR customers, or some combination

thereof. Therefore, to avoid any potential violation of the single use principle, I

have removed adjusted fuel and purchase power costs from the calculation of

the PFC revenue allocation percentage.

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Q. What adjustments have you made to the fuel and purchased power

costs?

A. I made two adjustments to fuel and purchased power costs. First, I reversed

the credit to PSCR fuel base for third party wholesale power sales gross

proceeds. This adjustment is necessary to preserve the gross proceeds from

third party wholesale power sales for disposition by the Commission. Second,

I reversed the credit to PSCR fuel base for non-PSCR interruptible sales. This

adjustment is necessary because non-PSCR interruptible revenue is available

to cover PFC and therefore must remain in both the revenue used to calculate

the PFC revenue allocation percentage and the actual revenue to which the

PFC revenue allocation percentage is applied. As shown on Exhibit No A-21

(MLH-1), “Production Fixed Cost Revenue Percentage, Pre-Interim Order –

2004” making these adjustments results in a Pre-Interim PFC revenue

allocation percentage of 18.10%.

Q. Won’t the higher PFC revenue allocation percentage that results from

your removal of adjusted fuel and purchase power costs from applicable

revenue increase the revenue available to contribute to 2004 actual PFC?

A. No. In accordance with the matching principle, Mr. Sadagopan has likewise

removed adjusted fuel and purchase power revenue from actual revenue.

Making these adjustments eliminates the potential error of over- or under-

stating PFC net stranded cost due to fuel-related costs and preserves third

party wholesale power sales gross proceeds for disposition by the

Commission.

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Q. Can you describe Exhibit No. A-22 (MLH-2), “Production Fixed Cost

Revenue Percentage, Interim Order – 2004”?

A. Yes. Exhibit No. A-22 (MLH-2) shows my calculation of the Interim PFC

revenue allocation percentage. The Interim PFC revenue is calculated by

dividing the Interim PFC by the Interim Order revenue. The Interim PFC is

calculated as the sum of selected items of production revenue requirement.

Consistent with the Staff’s method, these items include the return on

production net plant, production depreciation expense, property taxes, and

insurance. The pre-tax rate of return of 9.88% is taken from the Interim Order

(MPSC Case No U-13808 Order dated February 20, 2004, pp 50). The Interim

Order revenue is calculated as the sum of Staff’s revenue plus the level of

interim relief granted. As further described below, the revenue and cost

adjustments necessary to properly calculate the PFC revenue allocation

percentage are also detailed on Exhibit No. A-22 (MLH-2). The result is an

Interim Order PFC revenue allocation percentage of 19.22%.

Q. In your calculation of the Interim Order PFC revenue allocation

percentage, how did you account for the fact that the Interim Order in

MPSC Case No. U-13808 deferred some issues to be ruled upon in the

Final Order?

A. In order to render a valid PFC revenue allocation percentage for the interim

period (February 21, 2004 – November 23, 2004), the Interim Order PFC must

be consistent with the Interim Order revenue. Since the rates put into effect by

the Interim Order were not designed to recover the Company’s full revenue

requirement, using the full PFC would overstate the PFC revenue allocation

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percentage. Therefore, the PFC calculation must be adjusted by the amount

of production fixed costs that were not granted in the Interim Order.

Determination of this adjustment required a comparison of the Interim and

Final orders which revealed that additional rate relief was granted in the Final

Order for two components. The Commission increased the level of Electric

Choice sales, worth $91.528 million (MPSC Case No. U-13808 Order dated

November 23, 2004, pp 59-60), and removed imputed discounts associated

with special manufacturing contracts, worth $37.845 million (MPSC Order

dated November 23, 2004, pp 76).

Q. What portion of the additional rate relief granted in the Final Order is

production related?

A. I believe that all of the $91.528 million of rate relief associated with increased

Electric Choice sales levels is production related. I draw this conclusion by

recognizing that the overall level of sales within Detroit Edison’s service area

contained in the Final Order was the same as that upon which the Interim

Order was based; only the composition of the sales changed. Furthermore,

Electric Choice customers continue to receive distribution service from Detroit

Edison. Therefore, increasing the Electric Choice sales level and decreasing

full service customer sales produced the need for additional production-related

cost recovery.

With regard to the $37.845 million of discounts associated with special

manufacturing contracts, I believe that the discounts are related to both

production and distribution. To determine the portion that is production

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related, I prorated the total discount amount based on the unbundled cost of

service that I developed and filed in Case No. U-14399 for the applicable

unbundled rate for special manufacturing contract customers, i.e. the

Transitional Primary Supply Rate - D7.

Q. Once you determined the portion of the additional rate relief granted in

the Final Order that was production related, how did you adjust the

Interim PFC?

A. The adjustment to the Interim PFC must consider only the fixed portion of the

additional relief granted in the Final Order. I determined the fixed portion of

the production-related Final Order rate relief based on the fixed portion of the

production revenue requirement filed in MPSC Case No. U-14399 and

removed them from the Interim PFC. This is a reasonable basis for

determining the fixed portion of production-related Final Order rate relief

because the unbundled production revenue requirement in MPSC Case No. U-

14399 is based upon the Final Order in MPSC Case No. U-13808.

Q. Were there other adjustments necessary to properly calculate the Interim

Order PFC?

A. Yes. It was necessary to remove the deferred Clean Air Act (“CAA”) costs.

Q. Why was it necessary to remove the deferred CAA Costs?

A. The Commission set interim rates at a level sufficient to cover only 70% of the

CAA costs (MPSC Case No. U-13808 Interim Order dated February 20, 2004,

page 57). The remaining 30% was held in abeyance for consideration in the

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Final Order. Therefore, I removed 30% of the cost associated with CAA

compliance from the Interim PFC.

Q. What was the source of the Interim Order Revenue?

A. Interim Order revenue was taken from MPSC Case No U-13808, Staff Exhibit

No. S-50 (WGA-1), page 10 of 10. This Exhibit has a column that shows the

Revenue Before Surcharge. I used the revenue that corresponds to the

ordered stranded cost transition charge of 4 mills/kWh. To this I added the

$248 million of interim rate relief.

Q. Were additional adjustments necessary to calculate the appropriate

Interim Order revenue for use in calculating the Interim Order PFC

revenue allocation percentage?

A. Yes. In keeping with the principle of single application, I made adjustments to

reflect the fact that a portion of the Interim Order revenue was not available to

contribute to PFC as shown on Exhibit No. A-22 (MLH-2), “Production Fixed

Cost Revenue Percentage, Interim Order – 2004”. In order to be consistent

with the Staff Method, I also removed revenue from sources other than

ultimate customers.

Q. What revenue is not available to contribute to PFC?

A. Revenue not available to contribute to PFC includes revenue that the

Company has an obligation/liability to remit to external funds. These include

securitization, nuclear decommissioning, the Low Income Energy Efficiency

Fund (“LIEEF”) and minimum contributions to the Detroit Edison Pension

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Fund. In addition, adjusted PSCR-related costs are not available to contribute

to 2004 PFC and therefore they are removed. Mr. Sadagopan likewise

removed the 2004 PSCR-related actual cost. As in the pre-interim calculation,

making this adjustment eliminates the potential error of over- or under- stating

stranded cost due to PSCR-related costs and preserves the gross proceeds

from third party wholesale power sales for disposition by the Commission.

Q. Why do you remove minimum contributions to the Detroit Edison

Pension Fund?

A. The Interim Order was conditioned upon the agreement that Detroit Edison

would make the minimum annual pension contributions of $113.475 million

(MPSC Case No. U-13808, Interim Order issued February 20, 2004, pp 64).

Clearly, these revenues cannot be used both as a contribution to Detroit

Edison’s pension fund and to offset PFC. However, since a portion of the

minimum pension contribution related to Administrative and General

Overheads was capitalized, I remove the remaining $86.767 million.

Q. What revenue came from sources other than ultimate customers?

A. Revenue included in Interim Order revenue that came from sources other than

ultimate customers includes miscellaneous revenue (i.e. revenue derived from

alternative uses of equipment that is included in rate base, such as the

revenue rent received from cable television companies for attaching their cable

to Detroit Edison’s poles), and revenue from Electric Choice customers.

Stranded Cost transition charge revenue is collected to amortize PFC net

stranded costs from historical periods and therefore is not reflected in the PFC

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revenue allocation calculation.

Q. Can you describe Exhibit No. A-23 (MLH-3), “Production Fixed Cost

Revenue Percentage, Final Order – 2004”?

A. Yes. Exhibit No. A-23 (MLH-3) shows my calculation of the Final Order PFC

revenue allocation percentage. The Final Order PFC is calculated in the same

manner as the Interim PFC, i.e. as the sum of selected items of production

revenue requirement. Consistent with the Staff Method, these items include

the return on production net plant, production depreciation expense, property

taxes, and insurance. The pre-tax rate of return of 9.74% is taken from the

Final Order (MPSC Case No. U-13808 Order dated November 23, 2004, pp

64). Revenue and adjustments necessary to properly calculate the PFC

revenue allocation percentage are also detailed on the exhibit. These include

removal of revenue that is not available to contribute to PFC and revenue from

sources other than ultimate customers. The result is a Final Order PFC

revenue allocation percentage of 24.06%.

Q. Can you describe Exhibit No. A-24 (MLH-4), “Jurisdictional Factors for

Production Fixed Costs”

A. Yes. Exhibit No. A-24 (MLH-4) shows the jurisdictional factors that apply to

production fixed costs. As used in my testimony, “jurisdictional” or

“jurisdictionalization” refers to separating the costs associated with providing

electric service to retail customers, which falls under MPSC jurisdiction, from

those costs associated with providing service at wholesale, which is subject to

FERC jurisdiction. This is typically accomplished within the cost of service

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study by applying allocation schedules, developed by applying a ratio to the

loads and sales associated with FERC jurisdiction to total electric utility loads

and sales, to total electric utility costs. The values used in this case originated

in MPSC Case No. U-13808.

Q. Can you describe Exhibit No. A-25 (MLH-5), “Production O&M Percentage

of Order Revenue”?

A. Yes. Exhibit No. A-25 (MLH-5) shows production O&M expense and

jurisdictional revenue corresponding to the Order in MPSC Case No. U-13808

expressed as a percentage of Order revenue. For the interim period, it was

necessary to remove the portion of the production O&M expense for which rate

relief was not granted until the Final Order. This adjustment is consistent with

that made to the Interim PFC revenue allocation percentage developed on

Exhibit No. A-22 (MLH-2). These percentages are used by Mr. Harvill to

support the reasonableness of the Company’s allocation of average 2004

production O&M to third party wholesale power sales. Mr. Sadagopan uses

the production O&M percentage of revenue to determine the actual 2004

revenue available to recover 2004 production O&M.

Q. Dos this conclude your pre-filed direct testimony?

A. Yes, it does.

MLH - 17




EXHIBITS

OF

MARTIN L. HEISER

Case No.: U-_______ Exhibit No.: A-21 (MLH-1)

Page: 1 of 1 Witness: M. L. Heiser

DETROIT EDISON Case No. U-12639Analysis of Contribution to Fixed Costs

Revised 2/12/04 Recalulated LB-1 w/o nuclear (a) (b) (c)PSCR Fuel & (a-b)

Total Purchased % ExclItem Juris Power PSCR

(A) Generation1 Production Plant in Service ($000) $4,544,3222 Production Depreciation Reserve ($000) $1,891,7403 Net Production Plant ($000) $2,652,582

4 Return on Net Prod Plant ($000) 7.66% $203,1885 Revenue Requirement Prod Plant ($000) 1.558 $316,567

6 Depreciation Expense Prod Plant ($000) $141,3457 Purchase Power Capacity ($000) $08 Prod Allocation of Other Taxes ($000) -1E+05 $71,5319 Insurance ($000) $0

10 (A) Production Plant Fixed Costs ($000) $529,443

11 COS Revenue ($000) $3,523,711 $559,537 $2,964,174 See WP-MLH-1, page 1, line 3

12 (A) as % of Revenue 15.03%

(B) Regulatory Assets13 SFAS 106 $59,42314 Return on Reg Assets ($000) 7.66% $4,55215 Revenue Requirement Reg Assets ($000) 1.558 $7,092

(C) PSCR Adjustment16 (C) Additonal Year 2000 PP Capacity ($000) $29,878

17 (A) + (B) Total Fixed Cost ($000) $536,534 $536,534

18 (A) + (B) as % of Electric Revenues COS 15.23% 18.10%

19 Year 2000 Revenue ($000) $3,808,051

20 (A) + (B) + (C) Contribution to Fixed Cost ($000) $609,707

21 Contribution to Fixed Cost from Ultimate Customers ($000) $611,602

MPSC Case No. U-13808Workpaper of Mr. Dan Blair, MPSC Staff

The Detroit Edison CompanyProduction Fixed Cost Revenue Percentage

Pre Interim Order - 2002

Removal of Fuel & Purchased Power

Case No.: U-_______Exhibit No.: A-22 (MLH-2)

Page: 1 of 1Witness: M. L. Heiser

Amount Source1 PRODUCTION FIXED COSTS2 Plant in Service 5,693,712 WP-MLH-2, page 1, line 8, col (b)3 Depreciation Reserve 2,660,597 WP-MLH-2, page 1, line 18, col (b)4 Net Plant 3,033,115 Line 2 - Line 35 Pre-tax Rate of return Interim 9.88% U-13808 Interim Order, page 506 Return & Tax 299,672 Line 4 X Line 57 Depreciation Excl Nuc Decomm 148,786 WP-MLH-2,page 1, line 28, col (b)8 Property Taxes 97,172 WP-MLH-3, line c9 Insurance 1,830 WP-MLH-4, page 1, line 310 Production Fixed Costs excl nuc dec. 547,459 Sum lines 6 through 911 Deferred CAA (20,410) WP-MLH-5, Interim Order U-13808, page 5712 Final rate relief fixed prod portion (77,251) WP-MLH-6, page 1, line 3, col (e)13 Total Adjusted Production Fixed Costs 449,798 14 REVENUE15 Total Revenue excluding relief 3,430,064 WP-MLH-7, line 516 Interim Rate Relief 248,430 WP-MLH-8 Interim Order, page 6517 Total Revenue including rate increase 3,678,494 Line 15 + Line 1618 Remove Revenue Not Available for PFC19 Securitization (B&T) (219,781) WP-MLH-9, line 58, col (e)20 Nuclear Decommissioning (38,902) WP-MLH-2, page 4, line 5, col (c)21 LIEEF (39,858) WP-MLH-10, Interim Order, page 4522 Adjusted Fuel & Purchased Power (786,145) WP-MLH-11, page 1, line 1223 Minimum Contribution to Pension Fund (86,757) WP-MLH-12, line 624 Remove Revenue from Sources Other than Ultimate Cust25 Misc Revenue (81,080) WP-MLH-13, line 57, col (g)26 Choice Revenue Excl Securitization & Nuc Decomm (86,135) WP-MLH-14, page 1, line 1027 Revenue from ultimate customers 2,339,836 Sum lines 17 thru 262829 PFC revenue Percentage 19.22% Line 13 / Line 27


Interim Order - 2004($000)



Amount Source1 PRODUCTION FIXED COSTS2 Plant in Service 5,693,712 WP-MLH-2, page 1, line 8, col (b)3 Depreciation Reserve 2,660,597 WP-MLH-2, page 1, line 18, col (b)4 Net Plant 3,033,115 Line 2 - Line 35 Pre-Tax Rate of Return (Final Order) 9.74% U-13808 Final Order page 646 Return & Tax 295,425 Line 4 x Line 57 Depreciation Excl Nuc Decomm 148,786 WP-MLH-2, page 1, line 28, col (b)8 Property Taxes 97,142 WP-MLH-3, line c9 Insurance 1,830 WP-MLH-4, page 1, line 310 Production Fixed Costs Excl Nuc Decomm. 543,183 Sum lines 6 through 911 REVENUE12 Total Revenue including rate increase 3,653,650 WP-MLH-13, line 58, col (g)13 Remove Revenue Not Available for PFC14 Securitization (B&T) (219,781) WP-MLH-9, line 58, col (e)15 Nuclear Decommissioning (38,902) WP-MLH-2, page 4, line 5, col (c)16 LIEEF (39,858) WP-MLH-10, Interim Order, page 4517 PSCR Cost (824,576) WP-MLH-15, line 15, col (d)18 Minimum Contribution to Pension Fund (86,757) WP-MLH-14, page 1, line 1019 Remove Revenue from Sources Other than Ultimate Cust20 Misc Revenue (81,080) WP-MLH-13, line 57, col (g)21 Choice Revenue Excl Securitization & Nuc Decomm (105,317) WP-MLH-14, line 422 Revenue from ultimate customers 2,257,380 Sum Lines 12 thru 202324 PFC revenue Percentage 24.06% Line 10 / Line 22


Final Order - 2004($000)

Case No.: U-_______ Exhibit No.: A-24 (MLH-4)

Page: 1 of 1 Witness: M. L. Heiser

JurisdictionalPercentage Source

1 Plant In Service 97.24% WP-MLH-2, page 1, line 9, col (b)2 Depreciation Reserve 97.19% WP-MLH-2, page 1, line 19, col (b)3 Depreciation Expense 97.57% WP-MLH-2, page 1, line 29, col (b)4 Property Tax 98.34% WP-MLH-2, page 55 Insurance 97.98% WP-MLH-2, page 6

The Detroit Edison CompanyProduction Jurisdictional Splits

($000)



1994 Production Direct O&M Source1 U-10102 Prod Operations excluding fuel 150,719 WP-MLH-16, page 1, line 392 U-10102 Prod Maintenance 176,721 WP-MLH-16, page 2, line 353 U-10102 Production O&M 327,440 Sum Lines 1 & 245 Pre-Interim Revenue 2,964,174 Exhibit No. A-21 (MLH-1), line 11, col (c67 Production O&M Percentage of Revenue 11.05% Line 3 / Line 589 2004 Production Direct O&M10 U-13808/U-14399 Prod Operations Excluding Fuel 174,806 WP-MLH-17, page 1, line 40, col (1)11 U-13808/U-14399 Prod Maintenance 207,089 WP-MLH-17, page 2, line 28, col (1)12 U-13808/U-14399 Production O&M 381,895 Sum Lines 10 & 111314 Removal of O&M not included in Interim Rate Relief (50,180) WP-MLH-6, page 1, line 3, col (f)15 Interim Production O&M 331,715 1617 Interim Revenue 2,339,836 Exhibit No. A-22 (MLH-2), line 271819 Production O&M Percentage of Interim Revenue 14.18% Line 15 / line 172021 Ordered Revenue 2,257,380 Exhibit No. A-23 (MLH-3), line 222223 Production O&M Percentage of Final Revenue 16.92% Line 12 / line 21

The Detroit Edison CompanyProduction O&M Percentage of Revenue

($000)




QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

RISHI S. SADAGOPAN

THE DETROIT EDISON COMPANY QUALIFICATIONS OF RISHI S. SADAGOPAN

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Q. What is your name and business address and by whom are you

employed?

A. My name is Rishi S. Sadagopan, and I am employed by The Detroit Edison

Company (“Detroit Edison” or “Edison” or “Company”). My business address

is The Detroit Edison Company, 2000 Second Avenue, Detroit, Michigan

48226.

Q. What is your present position with Edison?

A. I am a Principal Financial Analyst in the Regulatory Policy & Operations group.

This position, among other things, requires active involvement in rate cases.


A. In 1999, I received a Master of Business Administration degree, with a major in

Finance and Strategy, from the University of Michigan Business School. In

1990, I obtained a Master of Science degree in Environmental Engineering

from Virginia Tech. In addition, I graduated from the Indian Institute of

Technology in 1986 with a Bachelor of Science degree in Civil Engineering.

Q. Are you a registered professional engineer in the State of Michigan?

A. Yes, I am.

Q. What type of work have you done during your employment with Edison?

A. I have been employed by Edison since 2000. I was first assigned to the

Strategic Planning and Development Department as a Principal Analyst, where

I assisted in the development of the DTE/MCN merger implementation plan. I

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was the lead in the development and implementation of the “Capital

Investment Practice” for DTE Energy. The Capital Investment Practice

involved the development and implementation of the Capital Allocation model

for DTE Energy. I also was the lead in the development and implementation of

the Balanced Scorecard for DTE Energy. The Balanced Scorecard is a

strategy implementation and performance measurement tool. In February

2002, I was assigned to the Controller’s department. I have worked on the

implementation of FAS 71 regulated accounting, and implementation of FAS

143 Asset Retirement Obligation accounting. In November 2002, I moved to

the Regulatory Policy and Operations Group and have worked primarily on the

Stranded Cost and Electric cases discussed below.

Q. Mr. Sadagopan, what is the extent of your participation in prior Michigan

Public Service Commission (“MPSC”) cases?

A. I worked on the filing of Edison’s Net Stranded Cost case, Case No. U-13350,

helping prepare Exhibits and Workpapers required for that case and serving as

a backup for the Revenue Requirement witness. I was extensively involved in

Case No. U-13808, Edison’s most recent rate case. My involvement focused

on revenue requirements, cost of capital, and recovery of regulatory assets

and stranded costs. I supported the revenue requirement witness and helped

prepare the Exhibits and Workpapers supporting the Company’s position on

those issues in the case. I also analyzed MPSC Staff and Intervenor filings

and assisted in the preparation of the Company’s rebuttal case.

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Most recently, I sponsored testimony and exhibits regarding the Company’s

revenue requirement in MPSC Case No. U-14399, Edison’s Rate Unbundling

and Realignment Case.

Q. What was your work experience prior to joining Edison?

A. After graduation from the Indian Institute of Technology, I worked as a Civil

Engineer with Rao & Associates from 1986 to 1988. I worked on the design of

structures and performed market studies of the real estate market. In 1988, I

enrolled in the Master of Science program at Virginia Tech to pursue a degree

in Environmental Engineering.

In 1990, I joined Rust Environment & Infrastructure as a Consultant based in

Fairfax, VA. While with Rust, I worked on various utility consulting projects

that included water, wastewater, electric and gas. I worked with a team to

identify new business opportunities in water, wastewater and electric, which

resulted in a $3 million contract with Frederick County, VA. As part of the

contract, I worked on the design and construction of a treatment plant.

In 1994, I joined the Utility Department of the City of Kalamazoo as a Senior

Engineer and worked on various utility projects. I was in charge of the water

and wastewater annual capital projects. Also, I had responsibility for budget

preparation for the City and introduced Activity Based Costing for City services

which saved approximately $6 million annually. During this period, I managed

a number of complex capital projects. These included working with contractors

and engineers on the design and modification of the City’s water and

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wastewater plants. I also worked on cost reduction initiatives, budget

development, capital allocation, Requests for Proposals and Qualifications and

rate studies.

In 1999, I completed my Masters of Business Administration (MBA) at the

University of Michigan and joined Edison shortly thereafter.

RSS - 4

THE DETROIT EDISON COMPANY DIRECT TESTIMONY OF RISHI S. SADAGOPAN

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A. The Commission’s Order in Case No. U-13808, dated November 23, 2004,

indicated a need for a comprehensive true-up of the 2004 production fixed cost

(“PFC”) stranded cost calculation. The Commission ordered Edison to file its

2004 stranded cost case in conjunction with its PSCR reconciliation case to

ensure a comprehensive evaluation of its net stranded costs. In compliance

with the Commission’s U-13808 Order, the purpose of my testimony is to

support the calculation of Edison’s 2004 PFC net stranded costs. In addition, I

support the calculation of Production Operation and Maintenance (O&M)

revenues that Mr. Harvill uses in his testimony.

Q. Are you supporting any Exhibits in this case?

A. Yes, I am supporting the following Exhibits.

Exhibit No. A-26 (RSS-1) 2004 PFC Net Stranded Costs

Exhibit No. A-27 (RSS-2) 2004 Production Fixed Cost Revenues

Exhibit No. A-28 (RSS-3) 2004 Production O&M Revenues


A. Yes, they were.

Q. What is the purpose of Exhibit No. A-26 (RSS-1)?

A. The purpose of Exhibit No. A-26 (RSS-1) is to present the Company’s

calculation of its PFC net stranded costs for 2004. The methodology used for

calculating the 2004 PFC stranded costs follows the methodology for

calculating the 2002 and 2003 stranded costs in Case No. U-13808. This

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methodology has been modified to reflect changes in circumstances in 2004

as compared to years 2002 and 2003, such as the reinstatement of the Power

Supply Cost Recovery (“PSCR”) clause. The data on this Exhibit are derived

from the Company’s forthcoming 2004 Annual Report to the Michigan Public

Service Commission, Form No. P-521.

Q. Can you explain the calculation of the Production Fixed Costs on Exhibit

No. A-26 (RSS-1)?

A. Yes. Exhibit No. A-26 (RSS-1), lines 1 through 11, details the components of

the revenue requirement of Edison’s fixed costs of generation. Line 10

removes the costs associated with Clean Air Act expenditures that are

explained further below. All the direct costs listed are jurisdictional costs. In

order to determine the required return on Edison’s 2004 net production plant, I

developed a composite pre-tax rate of return of 9.88%. This composite pre-tax

rate of return reflects the Commission-authorized pre-tax rate of return for the

Pre-Interim period (January 1 through February 20, 2004), Interim Order

period (February 21 through November 23, 2004) and Final Order period

(November 24 through December 31, 2004).

Q. What are the three different Commission authorized pre-tax rates of

return for the year 2004 used to develop the composite rate?

A. The Commission-authorized pre-tax rates of return for 2004 are as follows:

(1) For the Pre-Interim Order period, the Company used the Commission

approved rate of 10.01% from MPSC Case No. U-10102.

(2) For the Interim Order period, the Company used the Commission

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approved rate of 9.88% from the February 20, 2004 Interim Order in

MPSC Case No. U-13808.

(3) And for the period after the Final Order, the Company used the

Commission-approved rate of 9.74% from the November 23, 2004 Final

Order in MPSC Case No. U-13808.

For the development of the return, a composite pre-tax rate of return was

calculated by weighting the three different pre-tax rates of return by the

number of days in the corresponding time periods for the year 2004. This

composite pre-tax rate of return is 9.88% as shown on line 4 of Exhibit No. A-

26 (RSS-1).

Q. Did you provide an offset for costs associated with the Clean Air Act

(“CAA”)?

A. Yes. Per the Commission Order in Case No. U-13808, costs associated with

CAA deferred as regulatory assets under section 10d(4) of Public Act 141 of

2000 should be recovered from full service retail customers. As a result line

10 on Exhibit No. A-26 (RSS-1) reduces revenue requirements for all 2004

cost deferrals related to CAA. These 2004 cost deferral amounts relating to all

customers prior to the Interim Order and for capped customers for the

remainder of the year will be recovered through the regulatory asset surcharge

mechanism as outlined in Case No. U-13808. Starting with the Interim Order,

revenues from uncapped customers includes their contribution for recovery of

remaining 2004 CAA costs.

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Q. Did you provide an offset for the costs associated with the capital

expenditures in excess of base depreciation?

A. No. The 2004 deferred amount for capital expenditures in excess of base

depreciation amount was non-production related. Hence no offset was made

to the stranded cost calculation that includes this offset.

Q. How are decommissioning costs associated with Fermi 2 treated?

A. The costs associated with the decommissioning of Fermi 2 and related asset

retirement costs have been removed from both net production plant and

depreciation expense, since the surcharge revenue to recover

decommissioning costs has also been removed as discussed below.

Q. How are property taxes and insurance costs included in PFC

determined?

A. The property taxes and insurance represent the actual costs incurred in 2004

by Edison for production related plants and are obtained from Company

records.

Q. Can you explain the calculation of revenues for contribution to

production fixed costs in Exhibit No. A-27 (RSS-2)?

A. Yes. The actual revenues collected by Edison from its full service or ultimate

customers are indicated on lines 6, 12 and 18 for the Pre-Interim, Interim and

Final Order periods, respectively. The philosophy behind the calculation of

these revenues is to be consistent and match the methodology used by Mr.

Heiser in the calculation of the PFC revenue allocation factors.

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The calculation begins with total revenue from sales to ultimate customers and

is adjusted to remove revenues with a dedicated funding purpose approved by

the Commission. The revenues removed are: the securitization bond and tax

charge revenue, Fermi 2 nuclear decommissioning surcharge revenue, the

dedicated funding for the Low Income and Energy Efficiency Fund (“LIEEF”),

pension expense related revenues, and the revenue associated with the

recovery of the PSCR Base, PSCR Factor and PSCR credits. The PSCR

factor revenue was adjusted to reflect refunds in accordance with the February

20th 2004 Interim Order (page 40). The PSCR credits include both third party

wholesale power sales proceeds, net of fuel, and non-PSCR interruptible

sales. Also, per the Staff methodology, historically revenues have been

imputed for large customer contract (“LCC”) and special manufacturing

contract (“SMC”) customers for the net stranded cost determination prior to the

pre-interim period.

Per the Interim Order issued on February 20, 2004 in Case No. U-13808 (page

55) the revenue deficiency in that case was reduced by the imputation of these

revenues. These revenues cannot be used twice i.e. once as part of the

revenue deficiency in the Interim Order and now as part of Edison’s stranded

cost. Hence I am not adding back these imputed revenues starting from the

date of the U-13808 Interim Order. In the Final Order, SMC imputed revenues

were eliminated as the SMC contracts expired.

These adjustments ensure consistency, and match the methodology used by

Mr. Heiser in calculating the PFC revenue allocation factor for the three

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different time periods in 2004. These adjusted total revenues are then

multiplied by the PFC revenue allocation factor to arrive at the revenue

contribution to production fixed cost. The derivation of the PFC revenue

allocation factors is addressed by Mr. Heiser.

Q. What is Detroit Edison’s 2004 PFC Net Stranded Costs?

A. Exhibit No. A-26 (RSS-1), the Company’s derives the Company’s actual PFC

stranded costs by subtracting the 2004 revenue contribution to production

fixed costs of $384 million on line 13 from the year 2004 revenue requirement

of production fixed costs of $507 million on line 11.

This results in a 2004 PFC stranded cost for Edison of $123 million as shown

on line 15 of this Exhibit. This stranded cost is then reduced by $8 million for

the approved recovery of PFC net stranded costs for the 2004 pre-interim

period in accordance with the November 23, 2004 Order in MPSC Case No. U-

13808. This stranded cost has been further reduced by $3 million for the

imputed gain on the sale of River Rouge per the Commission Order in Case

No. U-12266. Prior to the third party wholesale power sales offset, the

stranded costs are $112 million as indicated on line 24.

As explained in the testimony of Mr. Harvill and Mr. Byron, Edison proposes to

mitigate its stranded costs with third party wholesale power sales net proceeds

as indicated on line 26. As a result, Edison is requesting recovery of PFC net

stranded costs in the amount of $ 99 million, as shown on line 28 of Exhibit No.

A-27 (RSS-2), after the reductions described above. Mr. Falletich discusses

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the application of the transition charge to recover these PFC net stranded

costs.

Q. Is there a carrying charge on the unrecovered PFC net stranded cost

balance?

A. Yes, a carrying charge of 7% per year, as approved on page 97 in the Case

No. U-13808 Final Order, should be assessed on the unrecovered PFC net

stranded cost balance.

Q. Can you explain the calculation of revenues for contribution to

production O&M expense in Exhibit No. A-28 (RSS-3)?

A. Yes. The development of revenues for contribution to production O&M

expense is done in a manner similar to that for production fixed costs. The

production O&M revenue allocation factors for the three time periods is

developed by Mr. Heiser on his Exhibit No. A-25 (MLH-5). Upon applying the

production O&M revenue allocation factors to actual revenues for the three

time periods, I determined that the revenues available for contribution to

production O&M expense for 2004 amounted to $275 million as indicated on

line 20 of Exhibit No. A-28 (RSS-3). This revenue is used by Mr. Harvill to

support the reasonableness of the Company’s allocation of average 2004

production O&M to third party wholesale power sales.


A. Yes, it does.

RSS - 11




EXHIBITS

OF

RISHI S. SADAGOPAN

The Detroit Edison Company Case No.: U-_____2004 PFC Net Stranded Costs Exhibit No.: A-26 (RSS-1)($ 000) Page: 1 of 1

Witness: R. S. Sadagopan

(a) (b) (c)Line ActualNo. Description Source 200412 Direct Costs 3 Net Production Plant WP-RSS-1 Line 20, Col (e) 3,062,8004 Pre-Tax Rate of Return WP-RSS-3 Line 21, Col (c) 9.88%5 Return Required Line 3 x Line 4 302,714 6 Depreciation WP-RSS-1 Line 27, Col (e) 147,4917 Property Taxes WP-RSS-1 Line 29, Col (e) 89,5088 Insurance WP-RSS-1 Line 31, Col (e) 6,3289 Total Production Fixed Costs Sum of Lines 5 - 8 546,04210 Less: Clean Air Act Deferred Return on and of WP-RSS-6 38,618 11 Revenue Required for Fixed Generation Line 9 - Line 10 507,424 1213 Revenue for Contribution to Fixed Costs Exhibit A-27 (RSS-2) Line 20, Col (c) 384,111 1415 Total Stranded Costs Line 11 - Line 13 123,313 161718 Line 13/Line 11 75.70%1920 Less: Stranded Costs Recovered per Case No. U-13808 MPSC Staff Initial Brief - Pg 80 8,085 21 Less: River Rouge Gain Offset Case No. U-12266, Page 9 3,297 222324 Line 15 - Line 20 - Line 21 111,931 2526 Less: Third Party Wholesale Power Sales Net Proceeds Exhibit A-7 (JHB-7) Line 52, Col (b) 12,960 2728 PFC Net Stranded Costs Line 24-Line 26 98,971

Stranded Costs prior to Third Party Wholesale Power Sales Net Proceeds

Revenue for Contribution to Fixed costs/Rev Required for Fixed Generation %

The Detroit Edison Company Case No.: U-_____2004 Production Fixed Cost Revenues Exhibit No.: A-27 (RSS-2)($ 000) Page: 1 of 1


(a) (b) (c)Line ActualNo. Description Source 200412 Pre - Interim Order Period (Jan - Feb 20, 2004)34 Actual Revenues to Ultimate customers WP-RSS-2 Line 8 300,6875 Pre - Interim PFC Revenue allocation factor Exhibit A-21 (MLH-1) 18.10%6 Pre - Interim PFC Revenues Line 4 x Line 5 54,42478 Interim Order Period (Feb 21- Nov 23, 2004) *9

10 Actual Revenues to Ultimate customers WP-RSS-2 Line 8 1,474,42311 Interim PFC Revenue allocation factor Exhibit A-22 (MLH-2) 19.22%12 Interim PFC Revenues Line 10 x Line 11 283,3841314 Post Final Order Period (Nov 24 - Dec 2004) **1516 Actual Revenues to Ultimate customers WP-RSS-2 Line 8 192,44517 Post Final Order PFC Revenue allocation factor Exhibit A-23 (MLH-3) 24.06%18 Post Final Order PFC Revenues Line 16 x Line 17 46,3021920 Total PFC Revenues Line 6 + Line 12 + Line 18 384,111

* MPSC Case No. U-13808 Interim Order Dated February 20, 2004** MPSC Case No. U-13808 Final Order Dated November 23, 2004

The Detroit Edison Company Case No.: U-_____2004 Production O&M Revenues Exhibit No.: A-28 (RSS-3)($ 000) Page: 1 of 1


(a) (b) (c)Line ActualNo. Description Source 200412 Pre - Interim Order Period (Jan - Feb 20, 2004)34 Actual Revenues to Ultimate customers WP-RSS-2 Line 8 300,6875 Pre - Interim Production O&M Revenue allocation factor Exhibit A-25 (MLH-5) Line 7 11.05%6 Pre - Interim O&M Revenues Line 4 x Line 5 33,22678 Interim Order Period (Feb 21- Nov 23, 2004) *9

10 Actual Revenues to Ultimate customers WP-RSS-2 Line 8 1,474,42311 Interim Production O&M Revenue allocation factor Exhibit A-25 (MLH-5) Line 19 14.18%12 Interim O&M Revenues Line 10 x Line 11 209,0731314 Post Final Order Period (Nov 24 - Dec 2004) **1516 Actual Revenues to Ultimate customers WP-RSS-2 Line 8 192,44517 Post Final Order Production O&M Revenue allocation factor Exhibit A-25 (MLH-5) Line 23 16.92%18 Post Final Order O&M Revenues Line 16 x Line 17 32,5621920 Total Production O&M Revenues Line 6 + Line 12 + Line 18 274,861

* MPSC Case No. U-13808 Interim Order Dated February 20, 2004** MPSC Case No. U-13808 Final Order Dated November 23, 2004




QUALIFICATIONS

AND

DIRECT TESTIMONY

OF

EDWARD L. FALLETICH

THE DETROIT EDISON COMPANY QUALIFICATIONS OF EDWARD L. FALLETICH

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Q. Will you please state your name and business address?

A. My name is Edward L. Falletich. My business address is The Detroit Edison

Company, 2000 Second Avenue, Detroit, Michigan 48226.

Q. What is your present position with The Detroit Edison Company?

A. I am Manager of Pricing in the Regulatory Affairs Department.

Q. Will you please summarize your formal educational background?

A. I graduated from Lawrence Institute of Technology in 1980 with a Bachelor of

Science degree in Electrical Engineering. I have also taken several graduate-

level business courses at Wayne State University.

Q. Have you completed any other courses of study?

A. Yes. I have completed Power Systems Engineering, Economic Analysis,

Public Utility Accounting, Rate Setting in Public Utilities, Marginal Costing, and

various other rate/pricing-related seminars.

Q. Are you a member of any technical or professional organizations?

A. Yes. I am the Detroit Edison representative on the EEI Economic Regulation

and Competition Committee.

Q. Will you please summarize your business experience?

A. I joined Detroit Edison in 1969 in the Stores and Transportation Department.

In September 1970, I transferred to the Meter Department as a Single-Phase

Watthour Meter Tester and Group Work Leader.

ELF - 1

E.L. FALLETICH Line No.

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In January 1974, I transferred to the Revenue Requirement Department as an

Engineering Technician. I performed various economic and financial studies,

including preparation of annual depreciation studies.

In June 1976, I was promoted to Associate Economic Analyst. I assisted in the

preparation of working capital, rate base, revenue deficiency, and depreciation

studies.

In April 1979, I transferred to the Cost-of-Service Division as an Associate

Cost Analyst. My responsibilities included the preparation of cost-of-service

studies utilized in the Company’s electric rate case filings.

In June 1980, I was promoted to Senior Cost Analyst within the Cost-of-

Service Division. I was involved in the preparation of cost-of-service and unit

cost studies for both MPSC and FERC filings.

In October 1981, I transferred to the Rate Research Division of the Rate

Department. As a Principal Rate Research Engineer, my responsibilities

included designing and implementing rates; interpreting rates, rules and

regulations; and planning, developing, and directing engineering and economic

studies for rate design. In January 1984, I assumed the position of Acting

Supervisor of Rate Research.

In August 1988, I was appointed Supervisor of Product Pricing and Marketing

Issues. I was responsible for retail rate design, pricing policy/administration,

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interpreting rules/regulations, and load research. I also began functioning as

the regulatory interface with external customers on pricing matters.

In July 1993, I was appointed to the position of Director of Pricing with overall

responsibility for Pricing, Cost-of-Service, Load Research, and Customer

Options. In February 1998, the Pricing organization was transferred to the

Regulatory Affairs Department. I currently have responsibility for the Pricing

function. In 2002, the title of Director was changed to that of Manager.

Q. Have you testified previously before the Michigan Public Service

Commission or the Federal Energy Regulatory Commission?

A. Yes. I submitted cost-of-service and rate design testimony in the FERC Docket

Nos. ER81-213-000 and ER82-723-000. I have also testified in a number of

proceedings in Michigan on behalf of Detroit Edison. In Case No. U-6590-R, I

testified to the revenue impact of lifeline rates. In Case No. U-7660, I testified

to residential rate design and rules/regulations. In Case Nos. U-8789 and U-

10102, I testified to commercial, governmental, and industrial rates, standby

rates, allocation schedules, and billing determinants. In Case No. U-10646, I

testified regarding the Special Manufacturing Contracts. In Case No. U-11495,

I testified regarding special contract discounts and proposed Rider No. 10

revisions. In Case No. U-11726, I provided rebuttal testimony in the Fermi 2

amortization proceeding. In Case No. U-11956, I testified regarding the

revenue impacts of Electric Choice and the allocation of transition charges. In

Case No. U-12595, I submitted testimony regarding the implementation of

securitization charges and related rate reductions. In Case No. U-12639, I

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submitted testimony regarding the implementation of class specific

equalization transition charges. In Case No. U-13350, the Company’s 2002

filing to determine net stranded costs, I testified to the determination of the

proposed transition charge. In Case No. U-13808, I testified to the Company’s

proposed rate design, cost-of-service, Power Supply Cost Recovery (PSCR)

factor, and to various issues related to Electric Choice. In Case No. U-14399 I

have submitted testimony related to the proposed unbundling of Edison’s

tariffs and the removal of inter-class subsidies.

ELF - 4

THE DETROIT EDISON COMPANY DIRECT TESTIMONY OF EDWARD L. FALLETICH

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Q. What is the purpose of your direct testimony?

A. The purpose of my direct testimony is to develop and support the proposed

transition charges required to recover Detroit Edison’s 2004 net stranded

costs.

Q. Mr. Falletich, are you sponsoring any exhibits in this case?

A. Yes. I am sponsoring the following exhibit:

Exhibit No. A-29 (ELF-1) Proposed Transition Charges

Q. Was this exhibit prepared by you or under your direction?

A. Yes, it was.

Q. What are your recommendations with regards to transition charges?

A. I am proposing that the Commission implement a secondary Electric Choice

transition charge of 0.45¢/kWh and a primary Electric Choice transition charge

of 0.15¢/kWh in order to recover Detroit Edison’s 2004 net stranded costs of

$98.971 million. The net stranded cost amount is supported by Mr. Sadagopan

and is shown on Exhibit A-26 (RSS-1).

Q. How did you develop your proposed transition charges?

A. The development of my proposed transition charges is shown on Exhibit No.

A-29 (ELF-1) entitled “Proposed Transition Charges”. This exhibit identifies my

assumptions and considerations, calculates the number of years to fully

recover net stranded costs at various transition charge levels and details my

proposed Electric Choice transition charges of 0.45¢/kWh for secondary

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Electric Choice customers and 0.15¢/kWh for primary Electric Choice

customers. My key assumptions and considerations are as follows:

• The transition charges are designed to collect the 2004 net stranded cost

of $98.971 million as supported by Mr. Sadagopan.

• There should be a 3:1 ratio between the secondary and primary transition

charges. That is, the secondary Electric Choice transition charge should

be three times the primary Electric Choice transition charge. This is the

same ratio present in the existing secondary (0.30¢/kWh) and primary

(0.10¢/kWh) transition charges approved by the Commission in Case No.

U-13808. The Commission in Case No. U-13808 (November 23, 2004

Final Order – page 96) recognized that there is a significant difference in

headroom between the secondary and primary rate classes and as a

result set the secondary transition charge at a level of three times the

primary transition charge.

• I recommend that the transition charges be based on recovery of Detroit

Edison’s 2004 net stranded costs over approximately a three to five year

timeframe. This will result in a modest transition charge level for both

secondary and primary Electric Choice customers, and will also ensure

that the Company recovers its net stranded costs over a reasonable

timeframe.

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• My proposed transition charges are developed assuming the same level

of Electric Choice sales (9,250 GWH) as utilized by the Commission in its

determination of final rate relief for Detroit Edison in Case No. U-13808. I

have also utilized the same proportion of secondary and primary Electric

Choice sales (40% secondary/60% primary).

Q. How would you adjust your recommended transition charge levels if the

Commission were to approve a net stranded cost amount different than

that calculated by the Company?

A. If the Commission were to approve a different amount of net stranded costs, I

would propose that the secondary and primary transition charges be calculated

using the same parameters that I relied on in calculating the transition charges

on Exhibit No. A-29 (ELF-1), with one additional consideration. I would

recommend that the proposed transition charges be not less than the currently

approved transition charges of 0.30¢/kWh for secondary Electric Choice

customers and 0.10¢/kWh for primary Electric Choice customers. This may,

for example, result in net stranded cost recovery over something less than

three years, but this is appropriate in my opinion as it at least maintains the

existing Commission approved transition charge levels.

Q. Do you have any other recommendations?

A. Yes. The calculation of transition charges is based on many factors, such as

Electric Choice sales levels and Electric Choice sales mix, which could change

over time, and impact the timetable for recovery of Detroit Edison’s net

stranded costs. I would recommend that following the first 12 months of net

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stranded cost recovery, a true-up proceeding be commenced for the purpose

of determining whether the transition charges approved in this proceeding

need to be modified. The scope of this true-up proceeding would be limited to

a review of Electric Choice sales levels and sales mix.

Q. Does this conclude your direct testimony?

A. Yes, it does.

ELF - 8




EXHIBIT

OF

EDWARD L. FALLETICH

Case No.: U-_________ Exhibit No. A-29 (ELF-1) Page 1 of 1 Witness: E. L. Falletich

The Detroit Edison Company Proposed Transition Charges

LineNo. Assumptions/Considerations1 • 2004 Net Stranded Costs (000's) -- per Exhibit A-26 (RSS-1) $98,9712 • Assumed Annual Electric Choice Sales (GWH) 9,2503 • Secondary % of Total Electric Choice Sales 40%4 • Primary % of Total Electric Choice Sales 60%5 • Utilized U-13808 Final Order Electric Choice Sales of 9,250 GWH and6 and 60% Primary/40% Secondary Split7 • Utilize Same Ratio as Currently Approved Transition Charges (secondary/primary 3:1)89 Years for

10 Transition Charge Level Full Recovery11 Secondary Primary of Net12 ¢/kWh ¢/kWh Stranded Costs13 0.30¢ 0.10¢ Current Charges 5.941415 0.35¢ 0.12¢ Approx. 5 Year Recovery 5.1016 0.40¢ 0.13¢ 4.4617 0.45¢ 0.15¢ Recommended 3.9618 0.50¢ 0.17¢ 3.5719 0.55¢ 0.18¢ 3.2420 0.60¢ 0.20¢ Approx. 3 Year Recovery 2.972122 Recommendations23 • Net stranded cost recovery period should be between 3 and 5 years.24 • Midpoint of this range (approx. 4 years) results in a proposed transition charge of 25 0.45¢/kWh for secondary and 0.15¢/kWh for primary.

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