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$: APPENDIX A Data Gathering Survey of Cruise Ships for A ... · PDF fileSeptember 2005 H:\POSF\Report\Final_090805\Final\APPENDIX A.doc A-4 C.9 Does the PMS control all aspects of electrical$
September 2005

H:\POSF\Report\Final_090805\Final\APPENDIX A.doc A-1

APPENDIX A

Data Gathering Survey of Cruise Ships

for

A Feasibility Study of Shoreside Power and Alternative Air Emission Technologies for Cruise Ships Berthed at the James R. Herman International Cruise Terminal, Piers 30-32,

Port of San Francisco

September 2005


Phase 1: Initial Data Gathering for Cruise Ship Selection From Marine Exchange and/or Port call data, collect the past 12-month vessel call records for all ships that called at the Port of San Francisco Cruise Ship Terminal. The vessel call records should include, but not limited to, the following information:

• Vessel name • Vessel IMO ID • Vessel type code • Vessel gross tonnage • Vessel date of build • Arrival dates/times • Departure dates/times • Flag • Operator’s name • Agent name

Based on these data, ENVIRON will recommend up to four vessels as potential candidates for shoreside power to reduce hoteling emissions at berth. Phase II: Data Gathering For Selected Vessels After receiving approval from the Port on the recommended vessels, the Port will ask the following ship and machinery questions to operators of the selected vessels to gather detailed data required for the shoreside power project. It should be noted that the California Air Resources Board (CARB) will also be sending out a ship survey form sometime in December 2004 for its state-wide, feasibility study of shoreside power for commercial marine applications, including cruise ships. Therefore, information provided here can be used in the CARB ship survey. Hull and Machinery A.1 Vessel Name_ ____________________________________________ A.2 IMO identification number (7 digits vessel number) __________________________ A.3 Main Propulsion System

Type of Drive System (e.g. diesel-electric, direct drive, geared drive, auxiliary power take-off etc) _________________________________________________________________________ Number of engines _________________________________________________________ Type (gas turbine or diesel engine)_______________________________________________ Rated capacity (total brake horsepower)______________________________________ Rated speed (rpm) ___________________________________________________________ Manufacturer _______________________________________________________________ Model No. _________________________________________________________________ Year built __________________________________________________________________ Fuel Purchase Specifications___________________________________________________-

A.4 Navigation System Type ______________________________________________________________________ Manufacturer________________________________________________________________ Model _____________________________________________________________________

September 2005


Year built __________________________________________________________________ A.5 Auxiliary generators/engines (Ship Service Engine)

Number of auxiliary engines ____________________________________________________ Generating capacity per engine (brake horsepower or kilowatts) _______________________ Displacement (litre/cylinder) __________________________________________________ Rated speed (rpm) ___________________________________________________________ Manufacturer _______________________________________________________________ Model _____________________________________________________________________ Year built __________________________________________________________________ Fuel Purchase Specifications____________________________________________________

Fuel Profiles

B.1 Sulfur content of fuel oil used in auxiliary engines Average (wt.%) _____________________________________________________________ Max (wt. %) ________________________________________________________________ B.2 Provide fuel consumption logs for each auxiliary engine

Electrical System

C.1 What is the operating voltage, frequency, and fault level of the main switch board? C.2 What type of distribution system is used onboard? C.3 What are the normal loads (kilowatts) on your main switchboard when the ship is

underway, maneuvering in port, and at dockside? C.4 Typically how much does this load fluctuate during the time the ship is at dockside? C.5 When in port and at dockside, how is electrical power generated? (by auxiliary

engine/generator set, or dual service propulsion engine/generator set) C.6 Where is the location of the main Switchboard on your ship (please provide distances

from Aft Perpendicular (AP), ship side shell port/starboard, and height above design baseline)? What is the normal range of hull draft during dockside operations?

C.7 Does your switchboard have a Spare Breaker on the main distribution panel? If so, what is its rating (amperage at which the breaker will trip)? If not, is there sufficient space by the switchboard for a spare breaker to be installed? C.8 What type of Power Management System (PMS) is operated on your ship? Is the PMS

manned or unmanned (fully automatic) and what type of class of system is it?

September 2005


C.9 Does the PMS control all aspects of electrical distribution on your ship? If not, please list

all loads that are not controlled by the ship PMS. C.10 What is the distance of the Engine Room aft and fwd bulkheads from the aft

perpendicular? Can a GA be provided? C.11 Is there an existing point of entry in the hull that would serve as a suitable place to bring

shore power cables onboard? Please specify this location by distance from AP, side of ship, and height above baseline. Please note that the refueling station is not recommended due to EX ratings.

C.12 If there is no existing point of entry that would be suitable, please indicate your

recommended location where one could be installed, by distance from AP, side of the ship, and height above baseline.

C.13 What type of grounded system does the ship have (positive or negative)?

September 2005

H:\POSF\Report\Final_090805\Final\APPENDIX B.doc B-1

APPENDIX B

Lloyd’s Vessel and Generator Data

September 2005


Nos Maker Model KW rpm bore (mm)stroke (mm Nos Maker Model KW Voltage2 Fincantieri/Sulzer 16ZAV40S 12800 2 ABB Stromberg AMG 11570 110003 Fincantieri/Sulzer 12ZAV40S 9872 3 ABB Stromberg AMG 8638 110002 Wartsila 16V46 16800 2 Brushgbi D275-T14 16200 110001 GEC Alsthom LM2500 29083 1 GEC Alsthom BDAX7 25000 11000

DAWN PRINCESS 4 Fincantieri/Sulzer 16ZAV40S 11650 510 400 560 4 NA NA 11128 66001 GE, Gas turbine LM2500+ 25000 1 Brushgri BDAX72-193ERH 25000 110002 Wartsila 9L46C 9450 2 GEC Machines D225T14 9150 110002 Wartsila 8L46C 8400 2 GEC Machines D225T14 8150 11000

3 NA NA 1649 440

2 MAN B&W 6L48/60 6300 514 480 600 2 MAN B&W 9L48/60 9450 514 480 600

3 MAN B&W 7L58/64 91003 MAN B&W 6L58/64 7800

NORWEGIAN SPIRIT (ex-SuperStar Leo) 4 MAN B&W 14V48/60 14700 4 NA NA 14000 NANORWEGIAN STAR 4 MAN B&W 14V48/60 14700 4 NA NA NA 11000

3 MAN B&W 7L58/64 99843 MAN B&W 6L58/64 64201 GE Gas turbine LM2500 23300 1 Brushgri BDAX62-170ERH 14000 110003 Fincantieri/Sulzer 16ZAV40S 11520 3 ABB Stromberg AMG 11200 110002 Fincantieri/Sulzer 12ZAV40S 8640 2 ABB Stromberg AMG 8400 110002 GE Gas turbine LM2500 25000 2 NA NA 25000 110001 GE Steam turbine Unknown Unknown 1 NA NA 7500 11000

REGAL PRINCESS 4 MAN B&W 8L58/64 9720 428 580 640 4 NA NA 9410 66001 GE Gas turbine LM2500+ 25000 6 NA NA Yes Yes2 Wartsila 9L46C 94502 Wartsila 8L46C 8400

SEVEN SEAS MARINER 4 Wartsila 12V38 7920 4 NA NA 7650 6600SILVER SHADOW 2 Wartsila 8L46B 5737 NA

2 Brushgri NA 25000 11000GE Gas turbine 1 Brushgri NA 9450 11000

1 Leroy LSA 3000 11000SUN PRINCESS 1 B&W Hitachi 8L45GFCA 5804 NAVISION OF THE SEAS 4 Wartsila 12V46C 12600 4 NA NA 12600 6600

Fincantieri/Sulzer ABB Stromberg

YORKTOWN CLIPPER NA

Main Engine

CORAL PRINCESS

Main Generator

CRYSTAL HARMONY 4 MAN/Mitsubishi 8L58/64 8640 428 580 640 4 Stromberg N/K 8250 6600

DIAMOND PRINCESS

MAXIM GORKIY NA 8334

MERCURY

NORWEGIAN SKY/PRIDE OF ALOHA 6 NA NA NA 10000

NORWEGIAN SUN 6 NA NA NA 10000

OOSTERDAM

2 AEG Steam turbine

RADIANCE OF THE SEAS

AMSTERDAM

SAPPHIRE PRINCESS

SUMMIT 2 LM2500+ 29000

VOLENDAM

Vessel

5 12ZAV40S 8640 5 HSG1600 8400 6600

September 2005


Nos Maker Model KW Nos Maker Model KW Voltage Frequency1 Italiani 1712T3TE 12001 ListerPET TS2 10

1 Wartsila 8R32E 32401 Detroit USA 8163-7305 612

DAWN PRINCESS 0 1 NA NA 600 440 60

3 NA NA 1650 220/380 502 NA NA 360 220/380 50

4 MANBW DIESELGEU 6L-40/54 4420 2 KAICK DIDBN 5200 6600 601 CUMMINSUSA KTA-50G2 1007 4 KAICK DIDBN 4100 6600 60

1 KAICK DSG 840 660 600 0

NORWEGIAN SPIRIT (ex-SuperStar Leo) 0 0NORWEGIAN STAR 0 0

0 0

1 Italiani 1712T3TE 1200 01 DEUTZAG F6L912 78

REGAL PRINCESS 0 00

SEVEN SEAS MARINER 0SILVER SHADOW 3 NA NA 2340

Mitsubishi NA

SUN PRINCESS 0 3 NA NA 550 445 60VISION OF THE SEAS 0 0

1 Italiani 1712T3TE 880 01 ListerPET TS2 101 MWMDiter NA NA

YORKTOWN CLIPPER

60

VOLENDAM

Vessel

1 NA 3000 1 S16R-MPTA 1312

SAPPHIRE PRINCESS

SUMMIT

NA 3000 60RADIANCE OF THE SEAS

AMSTERDAM

1 NA

OOSTERDAM

NORWEGIAN SUN

KTA-50M2 1220

MERCURY

NORWEGIAN SKY/PRIDE OF ALOHA

DIAMOND PRINCESS

MAXIM GORKIY

2 CUMMINSGBI

NA 3000 6600 601 StrombergCRYSTAL HARMONY

1200 450 60

2 Mitsubishi S12R-MPTA 1140

NA

CORAL PRINCESS

Auxiliary Engine Auxiliary Generator

1 NA NA

September 2005

H:\POSF\Report\Final_091205\Final\APPENDIX C_all.doc C-1

APPENDIX C

Photographs of General Conditions of the Visible Distribution Lines and

Underground Vaults in the Area of the Mission and Embarcadero Substations

September 2005


September 2005


Intersection of 8th and Brannan, SW Corner, Looking East at Riser where Brannan Street Overhead Service Commences, No Vault Present

Intersection of Folsom and Spear Streets – Note OH Pole Where short OH Run (Fremont to Spear along Folsom) Goes Underground

September 2005

H:\POSF\Report\Final_090805\Final\APPENDIX D.doc D-1

APPENDIX D

Breakdown Cost Estimates for a Shoreside Power System

September 2005


Summary of Cost Estimates for a Conceptual Shoreside Power System for Cruise Ships Berthed at the Port of San Francisco

Item 1 - Meter to Substation Run Quantity Units Unit Cost Cost 10" Pavement Demo 2 SQFT $0.50 $1.0010" Pavement & 14" Base Removal/Landfill 0.145 Ton $12.00 $1.74Pavement Replacement 2 SQFT $2.00 $4.00Ductline 1 FT $27.50 $27.50Cable 1 FT $33.00 $33.00Manholes 1 FT $12.10 $12.10Subtotal $79.34Contingency 30% $23.80Total per LF $103.14Note: Ductline & manholes includes disposal of trench material and encasement

Item 2a- 2,000 kVA Substation Quantity Units Unit Cost Cost 10" Pavement Demo 810 SQFT $0.50 $405.0010" Pavement & 14" Base Removal/Landfill 117.45 TON $12.00 $1,409.40PCC Service Pad 30 CUYD $350.00 $10,500.00Fencing 109 LF $20.00 $2,180.00Bollards 27 EA $150.00 $4,050.00Gate 1 EA $150.00 $150.002,000 kVA 1 EA $25,900 $25,900.00Subtotal $44,594.40Contingency 30% $13,378.32Total Item $57,972.72

Item 2- 10,000 kVA Substation Quantity Units Unit Cost Cost 10" Pavement Demo 884 SQFT $0.50 $442.0010" Pavement & 14" Base Removal/Landfill 128.18 TON $12.00 $1,538.16PCC Service Pad 32.74 CUYD $350.00 $11,459.26Fencing 115 LF $20.00 $2,300.00Bollards 30 EA $150.00 $4,500.00Gate 1 EA $150.00 $150.0010,000 kVA 1 EA $90,100 $90,100.00Subtotal $110,489.42Contingency 30% $33,146.83Total Item $143,636.25Item 3 - Terminal Substation to

Wharf Run Quantity Units Unit Cost Cost 10" Pavement Demo 2 SQFT $0.50 $1.0010" Pavement & 14" Base Removal/Landfill 0.145 Ton $12.00 $1.74Pavement Replacement 2 SQFT $2.00 $4.00Ductline 1 FT $27.50 $27.50Cable 1 FT $22.00 $22.00Manholes 1 FT $12.10 $12.10Subtotal $68.34Contingency 30% $20.50Total per LF $88.84Note: Above includes disposal of trench material and encasement

September 2005


Item 4 - Run Under Wharf Quantity Units Unit Cost Cost Selective Concrete Demo and Coring 1 FT $2.50 $2.50Pipe Sleeve to Run Ducts In 1 FT $24.00 $24.00Ductline 1 FT $27.50 $27.50Cable 1 FT $22.00 $22.00Pipe Hangers 1 FT $7.50 $7.50Scaffolding 1 FT $10.00 $10.00Subtotal $93.50Contingency 30% $28.05Total per LF $121.55

Item 5 - Cable Reel Tower (double reel) Quantity Units Unit Cost Cost

Selective Concrete Demo & Disposal 68 CY $150.00 $10,200.00CIP Concrete Tower Foundation 50 SQFT $500.00 $25,000.00Precast Pull Box for HV Elect (H20 rated) 1 EA $3,000.00 $3,000.00Steel Cable Reel Tower 30"Dia Pipe 18 FT $1,400.00 $25,200.00Single Mono Spiral Cable Reel/Cable 1 EA $65,000.00 $65,000.00Davit 1 EA $4,000.00 $4,000.00Geared Turntable for Davit 1 EA $4,500.00 $4,500.00Winch, Sling & Rigging 1 EA $2,000.00 $2,000.00Pendant Controller 1 EA $1,500.00 $1,500.00240V Electrical Feed, Switch & Breaker 150 FT $35.00 $5,250.00Subtotal $145,650.00Contingency 30% $43,695.00Total ea. $189,345.00

Estimated cost of step down transformers

Primary: 12.5kV; Secondary 6.6 kV Transformer Footprint (ft.x ft.) Clearance (ft.) Equipment

2,000 kVA 5,000 kVA 7,500 kVA 10,000kVA front back sideOil-filled

Transformer with primary section

12 x 11 14.5 x 10 14.75 x 9.5 15.5 x 9.75 8 8 8

Outdoor-type Secondary Switchgear

with metering & main breaker

5 x 5.5 5 x 5.5 5 x 5.5 5 x 5.5 5 5 5

Fence Dimensions 30' x 27' 32' x 25'32.75' x

25.5'33.5' x 25.75' n/a n/a n/a

Weight (Lbs.)

25,900 42,200 49,200 56,000 n/a n/a n/a Cost $ 46,700 $ 63,600 $ 66,500 $ 90,100 n/a n/a n/a

September 2005

H:\POSF\Report\Final_090805\Final\APPENDIX E_cvrpg.doc E-1

APPENDIX E

PG&E E-20 Rate Schedules

Revised Cal. P.U.C. Sheet No. 21372-E Pacific Gas and Electric Company Cancelling Revised Cal. P.U.C. Sheet No. 20937-E San Francisco, California

COMMERCIAL/INDUSTRIAL/GENERAL SCHEDULE E-20—SERVICE TO CUSTOMERS WITH MAXIMUM DEMANDS OF 1,000 KILOWATTS OR MORE

CONTENTS: This rate schedule is divided into the following sections:

1. Applicability 12. Non-Firm Service Rates 2. Territory 13. Contracts 3. Firm Service Rates 14. Billing 4.

5. Definition Of Service Voltage Definition Of Time Periods

15. CARE Discount For Nonprofit Group-Living Facilities

6. 7. 8.

Power Factor Adjustments Charges For Transformer and Line Losses Standard Service Facilities

16. 17.

Optional Optimal Billing Period Service Electric Emergency Plan Rotating Block Outages

9. 10. 11.

Special Facilities Arrangements For Visual-Display Metering Non-Firm Service Program

18. 19. 20.

Standby Applicability Schedule S-Standby Service Special Conditions 1 through 6 Department of Water Resources Bond Charge

1. APPLICABILITY: Initial Assignment: A customer is eligible for service under Schedule E-20 if the

customer's maximum demand (as defined below) has exceeded 999 kilowatts for at least three consecutive months during the most recent 12-month period. If 70 percent or more of the customer's energy use is for agricultural end-uses, the customer will be served under an agricultural schedule.

Customer accounts which fail to qualify under these requirements will be evaluated for transfer to service under a different applicable rate schedule.

Customers who also request any meter data management services, must also sign an Interval Meter Data Management Service Agreement (Form 79-985) and must have an appropriate interval data meter. If the customer does not currently have this type of meter, the customer must pay PG&E for the cost of purchasing and installing an hourly interval meter, together with applicable Income Tax Component of Contribution (ITCC) charges and the cost to operate and maintain the interval meter, and must sign an Interval Meter Installation Service Agreement (Form 79-984).

The provisions of Schedule S—Standby Service Special Conditions 1 through 6 shall also apply to customers whose premises are regularly supplied in part (but not in whole) by electric energy from a nonutility source of supply. These customers will pay monthly reservation charges as specified under Section 1 of Schedule S, in addition to all applicable Schedule E-20 charges. Exemptions to standby charges are outlined in the Standby Applicability Section of this rate schedule.

Transfers Off of Schedule E-20: PG&E will review its Schedule E-20 accounts annually. A customer will be eligible for continued service on Schedule E-20 if its maximum demand has either: (1) Exceeded 999 kilowatts for at least 5 of the previous 12 billing months, or (2) Exceeded 999 kilowatts for any 3 consecutive billing months of the previous 14 billing months. If a customer's demand history fails both of these tests, PG&E will transfer that customer's account to service under a different applicable rate schedule, except as specified in the Energy Efficiency Adjustment provision below.

Assignment of New Customers: If a customer is new and PG&E believes that the customer's maximum demand will exceed 999 kilowatts and that the customer should not be served under a time-of-use agricultural schedule, PG&E will serve the customer's account under Schedule E-20.

(T) (T)

(Continued)

Advice Letter No. 2465-E-A Issued by Date Filed March 1, 2004 Decision No. 04-02-062 Karen A. Tomcala Effective March 1, 2004 Vice President Resolution No. 50436 Regulatory Relations



(Continued)

1. APPLICABILITY: (Cont’d.)

Definition of Maximum Demand: Demand will be averaged over 30-minute intervals. “Maximum demand” will be the highest of all the 30-minute averages for the billing month. If the customer’s use of electricity is intermittent or subject to violent fluctuations, a 5-minute or 15-minute interval may be used instead of the 30-minute interval. If the customer has any welding machines, the diversified resistance welder load, calculated in accordance with Section J of Rule 2, will be considered the maximum demand if it exceeds the maximum demand that results from averaging the demand over 30-minute intervals. The customer’s maximum-peak-period demand will be the highest of all the 30-minute averages for the peak period during the billing month. (See Section 5 for a definition of “Peak-Period.”)

Standby Demand: For customers for whom Schedule S—Standby Service Special Conditions 1 through 6 apply, standby demand is the portion of a customer’s maximum demand in any month caused by nonoperation of the customer’s alternate source of power, and for which a demand charge is paid under the regular service schedule.

If the customer imposes standby demand in any month, then the regular service maximum demand charge will be reduced by the applicable reservation capacity charge (see Schedule S Special Condition 1).

To qualify for the above reduction in the maximum demand charge, the customer must, within 30 days of the regular meter read date, demonstrate to the satisfaction of PG&E the amount of standby demand in any month. This may be done by submitting to PG&E a completed Electric Standby Service Long Sheet (Form 79-726).

Energy Efficiency Adjustment: A customer who implements measures to improve electrical energy efficiency on or after January 1, 1990, may be eligible to receive an energy efficiency adjustment. A customer will qualify for an energy efficiency adjustment if both following conditions are met: (1) the customer’s service was established prior to January 1, 1990, and (2) the energy efficiency measures reduce the customer’s maximum demand to the point that the customer would no longer be eligible for service under Schedule E-20.

To receive the energy efficiency adjustment, the customer must qualify for and sign an Agreement for Maximum Demand Adjustment for Energy Efficiency Measures (Form No. 79-758). The energy efficiency adjustment shall be the fixed reduction in demand specified in Form 79-758, and shall be added to the customer’s maximum demand for the sole purpose of determining the customer’s eligibility for Schedule E-20.

The energy efficiency adjustment specifically does not guarantee the customer’s continued eligibility for service under Schedule E-20. The energy efficiency adjustment will not be applied to the customer’s maximum demand for the purposes of calculating the monthly maximum demand charge.

(D) 2. TERRITORY: Schedule E-20 applies everywhere PG&E provides electricity service. (L)

(Continued)




(Continued)

3. FIRM SERVICE RATES: (Cont’d.)

Total bundled service charges are calculated using the total rates shown below. Direct Access (DA) and Community Choice Aggregation (CCA) charges shall be calculated in accordance with the paragraph in this rate schedule titled Billing.

TOTAL RATES

Total Customer/Meter Charge Rates Secondary

Voltage Primary Voltage

Transmission Voltage

Customer Charge Mandatory E-20 ($ per meter per day) $12.64887 $10.18480 $23.49076 Optional Optimal Billing Period Service ($ per meter per month) $130.00 $130.00 –

Optional Meter Data Access Charge ($ per meter per day) $0.98563 $0.98563 $0.98563

Total Demand Rates ($ per kW)

Maximum Peak Demand Summer $13.00 (R) $11.13 (R) $6.88 (R) Maximum Part-Peak Demand Summer $3.61 | $2.50 | $0.55 | Maximum Demand Summer $3.08 | $3.09 | $0.75 | Maximum Part-Peak Demand Winter $3.56 | $2.50 | $0.69 | Maximum Demand Winter $3.08 (R) $3.09 (R) $0.75 (R)

Total Energy Rates ($ per kWh)

Peak Summer $0.14725 (R) $0.12070 (R) $0.11281 (R) Part-Peak Summer $0.08380 | $0.07360 | $0.06799 | Off-Peak Summer $0.07682 | $0.07190 | $0.06556 | Part-Peak Winter $0.08919 | $0.08096 | $0.07723 | Off-Peak Winter $0.07663 (R) $0.07265 (R) $0.06853 (R)

Average Rate Limiter ($/kWh in summer months) $0.13995 $0.13995 – Peak Period Rate Limiter ($/kWh in summer months) $0.97708 $0.84876 $0.55750 Total bundled service charges shown on customers’ bills are unbundled according to the component rates shown below.

UNBUNDLING OF TOTAL RATES

Customer/Meter Charge Rates: Customer and meter charge rates provided in the Total Rate section above are assigned entirely to the unbundled distribution component.

Demand Rates by Component ($ per kW)

Generation: Maximum Peak Demand Summer $7.07 (R) $8.21 (R) $6.88 (R) Maximum Part-Peak Demand Summer $1.95 | $1.83 | $0.55 | Maximum Demand Summer ($3.68) | ($2.62) | ($3.87) | Maximum Part-Peak Demand Winter $1.92 | $1.83 | $0.69 | Maximum Demand Winter ($3.68) (R) ($2.62) (R) ($3.87) (R) Distribution: Maximum Peak Demand Summer $5.93 $2.92 $0.00 Maximum Part-Peak Demand Summer $1.66 $0.67 $0.00 Maximum Demand Summer $2.14 $1.09 $0.00 Maximum Part-Peak Demand Winter $1.64 $0.67 $0.00 Maximum Demand Winter $2.14 $1.09 $0.00 Transmission Maximum Demand* $2.44 $2.44 $2.44 Reliability Services Maximum Demand* $2.18 $2.18 $2.18

_______________

* Transmission, Transmission Rate Adjustments, and Reliability Service charges are combined for presentation on customer bills.

(Continued)

Advice Letter No. 2647-E-C Issued by Date Filed May 27, 2005 Decision No. Karen A. Tomcala Effective June 1, 2005 Vice President Resolution No. E-3933 100504 Regulatory Relations


COMMERCIAL/INDUSTRIAL/GENERAL SCHEDULE E-20— SERVICE TO CUSTOMERS WITH MAXIMUM DEMANDS OF 1,000 KILOWATTS OR MORE

(Continued)


UNBUNDLING OF TOTAL RATES (Cont’d.)

Energy Rates by Component ($ per kWh) Secondary



Generation: Peak Summer $0.11410 (R) $0.09835 (R) $0.09558 (R) Part-Peak Summer $0.05532 | $0.05216 | $0.05085 | Off-Peak Summer $0.04952 | $0.05058 | $0.04842 | Part-Peak Winter $0.05981 | $0.05898 | $0.06009 | Off-Peak Winter $0.04936 (R) $0.05129 (R) $0.05139 (R) Distribution: Peak Summer $0.01383 $0.00417 $0.00027 Part-Peak Summer $0.00916 $0.00326 $0.00018 Off-Peak Summer $0.00798 $0.00314 $0.00018 Part-Peak Winter $0.01006 $0.00380 $0.00018 Off-Peak Winter $0.00795 $0.00318 $0.00018 Transmission Rate Adjustments* (all usage) $0.00016 (I) $0.00016 (I) $0.00016 (I) Public Purpose Programs (all usage) $0.00454 $0.00402 $0.00326 Nuclear Decommissioning (all usage) $0.00035 $0.00035 $0.00035 Competition Transition Charge (all usage) $0.00434 $0.00372 $0.00326 Energy Cost Recovery Amount (all usage) $0.00534 $0.00534 $0.00534 DWR Bond (all usage) $0.00459 (R) $0.00459 (R) $0.00459 (R)

_______________


(Continued)




(Continued)


a. TYPES OF CHARGES: The customer's monthly charge for service under Schedule E-20 is the sum of a customer charge, demand charges, and energy charges:

– The energy charge is the sum of the energy charges from the peak, partial-peak, and off-peak periods. The customer pays for energy by the kilowatt-hour (kWh), and rates are differentiated according to time of day and time-of-year.

– The monthly charges may be increased or decreased based upon the power factor. (See Section 6.)

– The customer charge is a flat monthly fee.

(D)

(T)

(Continued)




(Continued)


a. TYPES OF CHARGES: (Cont’d.)

– Schedule E-20 has three demand charges, a maximum-peak-period-demand charge, a maximum-part-peak-period demand charge, and a maximum-demand charge. The maximum-peak-period-demand charge per kilowatt applies to the maximum demand during the month’s peak hours, the maximum-part-peak-demand charge applies to the maximum demand during the month's part-peak hours, and the maximum-demand charge per kilowatt applies to the maximum demand at any time during the month. The bill will include all of these demand charges. (Time periods are defined in Section 5.)

– As shown on the rate chart, which set of customer, demand, and energy charges is paid depends on the voltage at which service is taken. Service voltages are defined in Section 4 below.

– Please note that the rates in the chart on the preceding page apply only to firm service. Rates for non-firm service can be found in Section 12 of this rate schedule.

b. AVERAGE RATE LIMITER (applies to bundled, firm service only): If the customer takes service on Schedule E-20, in either the secondary or primary voltage class, bills will be controlled by a “rate limiter” during the summer months. The bill will be reduced if necessary so that the average rate paid for all demand and energy charges less the Energy Rate Adjustment (ERA) amount calculated using the applicable rates provided in Schedule E-ERA during a summer month does not exceed the rate limiter shown on this schedule. This provision will not apply if the customer has elected to receive separate billing for back-up and maintenance service pursuant to Special Condition 8 of Schedule S.

Reductions in revenue resulting from application of the average rate limiter will be reflected as reduced distribution amounts for billing purposes.

c. PEAK-PERIOD RATE LIMITER (applies to bundled, firm service only): If the customer takes service on Schedule E-20 at any service voltage level, bills will be controlled by a “peak-period rate limiter” during the summer months. The bill will be reduced if necessary so that the average rate paid for all on-peak demand and energy charges less the peak period ERA amount calculated using the applicable rates provided in Schedule E-ERA during the peak period in a summer month does not exceed the peak-period rate limiter shown on this schedule. This provision will not apply if the customer has elected to receive separate billing for back-up and maintenance service pursuant to Special Condition 8 of Schedule S.

Reductions in revenue resulting from application of the peak-period rate limiter will be reflected as reduced distribution amounts for billing purposes.

(T) (T)

(T) (T)

(Continued)

Advice Letter No. 2556-E Issued by Date Filed September 17, 2004 Decision No. 04-02-062 Karen A. Tomcala Effective November 1, 2004 Vice President Resolution No. 52927 Regulatory Relations



(Continued)

4. DEFINITION OF SERVICE VOLTAGE:

The following defines the three voltage classes of Schedule E-20 rates. Standard Service Voltages are listed in Rule 2.

a. Secondary: This is the voltage class if the service voltage is less than 2,400 volts or if the definitions of "primary" and "transmission" do not apply to the service.

b. Primary: This is the voltage class if the customer is served from a "single customer substation" or without transformation from PG&E's serving distribution system at one of the standard primary voltages specified in PG&E's Electric Rule 2, Section B.1.

c. Transmission: This is the voltage class if the customer is served without transformation at one of the standard transmission voltages specified in PG&E's Electric Rule 2, Section B.1.

5. DEFINITION OF TIME PERIODS:

Times of the year and times of the day are defined as follows:

SUMMER Period A (Service from May 1 through October 31):

Peak: 12:00 noon. to 6:00 p.m. Monday through Friday (except holidays)

Partial-peak: 8:30 a.m. to 12:00 noon AND 6:00 p.m. to 9:30 p.m. Monday through Friday (except holidays).

Off-peak: 9:30 p.m. to 8:30 a.m. Monday through Friday All day Saturday, Sunday, and holidays

WINTER Period B (service from November 1 through April 30):

Partial-Peak: 8:30 a.m. to 9:30 p.m. Monday through Friday (except holidays).

Off-Peak: 9:30 p.m. to 8:30 a.m. Monday through Friday (except holidays). All day Saturday, Sunday, and holidays

HOLIDAYS: "Holidays" for the purposes of this rate schedule are New Year's Day, President's Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. The dates will be those on which the holidays are legally observed.

CHANGE FROM SUMMER TO WINTER OR WINTER TO SUMMER: When a billing month includes both summer and winter days, PG&E will calculate demand charges as follows. It will consider the applicable maximum demands for the summer and winter portions of the billing month separately, calculate a demand charge for each, and then apply the two according to the number of billing days each represents.

(D)

(Continued)

Advice Letter No. 2310-E Issued by Date Filed November 25, 2002 Decision No. Karen A. Tomcala Effective December 5, 2002 Vice President Resolution No. 47003 Regulatory Relations



(Continued)

6. POWER FACTOR ADJUSTMENTS:

The bill will be adjusted based upon the power factor. The power factor is computed from the ratio of lagging reactive kilovolt-ampere-hours to the kilowatt-hours consumed in the month. Power factors are rounded to the nearest whole percent.

The rates in this rate schedule are based on a power factor of 85 percent. If the average power factor is greater than 85 percent, the total monthly bill will be reduced by 0.06 percent of the bundled service bill less any taxes and the ERA amount calculated using applicable rates provided in Schedule E-ERA for each percentage point above 85 percent. If the average power factor is below 85 percent, the total monthly bill will be increased by 0.06 percent of the bundled service bill less any taxes and the ERA amount calculated using applicable rates provided in Schedule E-ERA for each percentage point below 85 percent.

Power factor adjustments will be assigned to distribution for billing purposes.

(T) (T)

(T) (T)

7. CHARGES FOR TRANSFORMER AND LINE LOSSES:

The demand and energy meter readings used in determining the charges will be adjusted to correct for transformation and line losses in accordance with Section B.4 of Rule 2.

8. STANDARD SERVICE FACILITIES:

If PG&E must install any new or additional facilities to provide the customer with service under Schedule E-20, the customer may have to pay some of the cost. Any advance necessary and any monthly charge for the facilities will be specified in a line extension agreement. See Rules 2, 15, and 16 for details.

Facilities installed to serve the customer may be removed when service is discontinued. The customer will then have to repay PG&E for all or some of its investment in the facilities. Terms and conditions for repayment will be set forth in the line extension agreement.

9. SPECIAL FACILITIES:

PG&E will normally install only those standard facilities it deems necessary to provide service under Schedule E-20. If the customer requests any additional facilities, those facilities will be treated as "special facilities" in accordance with Section I of Rule 2.

10. ARRANGEMENTS FOR VISUAL-DISPLAY METERING:

If the customer wishes to have visual-display metering equipment in addition to the regular metering equipment, and the customer would like PG&E to install that equipment, the customer must submit a written request to PG&E. PG&E will provide and install the equipment within 180 days of receiving the request. The visual-display metering equipment will be installed near the present metering equipment. The customer will be responsible for providing the required space and associated wiring.

PG&E will continue to use the regular metering equipment for billing purposes.

(Continued)

Advice Letter No. 2556-E Issued by Date Filed September 17, 2004 Decision No. 04-02-062 Karen A. Tomcala Effective November 1, 2004 Vice President Resolution No. 52928 Regulatory Relations

Revised Cal. P.U.C. Sheet No. 22112-E Pacific Gas and Electric Company Cancelling Revised Cal. P.U.C. Sheet No. 21021, San Francisco, California 21378-E


(Continued)

11. NON-FIRM SERVICE PROGRAM:

As noted, the rates in the chart in Section 3 of this rate schedule apply to firm service only. ("Firm" means service where PG&E provides a "continuous and sufficient supply of electricity," as described in Rule 14.) Certain customers may also elect to receive non-firm service under Schedule E-20.

In accordance with Decision 01-04-006, the Non-firm Service Program is closed to new or existing customers that are not currently in the program. Existing contracts may not be assigned to other parties. Customers considering participating in an interruptible program should refer to Schedule E-BIP for program terms and conditions, or may consider other available interruptible or demand response programs. The customer’s total load must meet the eligibility criteria in 11.a in order to participate in the Non-firm Service Program. Customers being served, as of December 31, 1992, under the Non-firm Service Program may continue to participate in the Non-firm Service Program.

This program is available for qualifying customers until modified or terminated in the rate design phase of the next general rate case or similar proceeding as ordered in Decision 02-04-060.

A customer who elects to receive non-firm service under Schedule E-20 must participate in PG&E's Emergency Curtailment Program. A non-firm service customer may also elect to participate in PG&E's Underfrequency Relay (UFR) Program.

EMERGENCY CURTAILMENT PROGRAM: Under the Emergency Curtailment Program, a non-firm service customer may be requested to reduce demand to a designated number of kilowatts (kW), referred to as the customer's contractual "firm service level." PG&E will make requests for such curtailments from its non-firm service customers upon notification from the California Independent System Operator (ISO) that a system-wide or local operating condition exists which will impair the ability of the ISO to meet the demands of PG&E’s other customers. The ISO is expected to issue load curtailment directives to PG&E in those instances where load reductions are necessary in order to maintain system-wide operating reserves above the 5 percent level throughout the next operating hour, or if such load reductions are the sole remaining measure available in order to mitigate transmission overloads in the PG&E area.

(Continued)

Advice Letter No. 2555-E Issued by Date Filed September 16, 2004 Decision No. Karen A. Tomcala Effective March 1, 2004 Vice President Resolution No. 52954 Regulatory Relations



(Continued)

11. NON-FIRM SERVICE PROGRAM: (Cont’d.)

UNDERFREQUENCY RELAY PROGRAM: Under this program, the customer agrees to be subject at all times to automatic interruptions of service caused by an underfrequency relay device that may be installed by PG&E.

Please note that PG&E may require up to three years' written notice for a change from non-firm to firm service, or for termination of participation in the Underfrequency Relay Program.

a. ELIGIBILITY CRITERIA FOR NON-FIRM SERVICE: To qualify for non-firm service, the customer must have had an average peak-period demand of at least 500 kW during each of the last six summer billing months prior to the customer's application for non-firm service. (Average peak-period demand is the total number of kWh used during the peak-period hours of a billing month divided by the total number of peak-period hours in the month.) Customers who have not yet had six months of summer service must demonstrate to PG&E's satisfaction that they will maintain an average monthly-peak-period demand of 500 kW or more to qualify for non-firm service.

Customers on non-firm service may not have, or obtain, any insurance for the sole purpose of paying non-compliance penalties for willful failure to comply with requests for curtailments. Customers with such policy will be terminated from the Program, and will be required to pay back any incentives that the customer received for the period covered by the insurance. If the period cannot be determined, the recovery shall be for the entire period the customer was on the program. Eligibility for the non-firm program requires that each customer execute and submit to PG&E a No Insurance Declaration that states that the customer does not have, and will not obtain such insurance.

Customers who are deemed essential under the Electric Emergency Plan as adopted in Decision 01-04-006 and Rulemaking 00-10-002, must submit to PG&E a written declaration that states that the customer is, to the best of that customer’s understanding, an essential customer under Commission rules and exempt from rotating outages. It must also state that the customer voluntarily elects to participate in an interruptible program for part of its load based on adequate backup generation or other means to interrupt load upon request by the respondent utility, while continuing to meet its essential needs. In addition, an essential customer may commit no more than 50% of its average peak load to interruptible programs.

(D)

(N) |

(N)

(Continued)

Advice Letter No. 2453-E Issued by Date Filed December 23, 2003 Decision No. Karen A. Tomcala Effective February 1, 2004 Vice President Resolution No. 49895 Regulatory Relations

Revised Cal. P.U.C. Sheet No. 22113-E Pacific Gas and Electric Company Cancelling Original Cal. P.U.C. Sheet No. 21023, San Francisco, California 20942-E


(Continued)


b. DESIGNATION OF FIRM SERVICE LEVEL: If a customer takes non-firm service, the designated number of kW to which the customer must reduce demand during emergency curtailments is the customer’s contractual “firm service level.” This designated firm service level must be at least 500 kW less than the smallest of the customer’s average peak-period demands during the last six summer billing months prior to the designation.

c. PRE-EMERGENCY CURTAILMENT REQUIREMENTS: A customer may be requested to curtail, on a pre-emergency basis, up to a maximum of two times per year (except that any emergency curtailments will count towards the maximum). Each pre-emergency curtailment will last no more than five hours. Customers will be given at least 30 minutes notice before each curtailment. The pre-emergency curtailments will be requested subject to the criteria listed in Section 11.d below, and PG&E’s discretion.

d. PRE-EMERGENCY CURTAILMENT PROCEDURE: PG&E will notify the customer by telephone, electronic mail, or other reliable means of communication. This notification will designate the time by which the customer’s kW demand is requested to reduce to the customer’s contractual firm service level. The notification will also designate the time when the customer may resume use of full power.

PG&E may call a pre-emergency curtailment if one of the following criteria are met:

1) The 9:00 a.m. forecast of temperatures in the Central Valley (the average of the forecasted temperature in Fresno and Sacramento) exceeds 100 degrees Fahrenheit; and PG&E has been informed by the ISO that an adjusted 10:00 a.m. forecast of two-hour reserves for that afternoon’s peak is 12 percent or less; or

2) The 9:00 a.m. forecast of temperatures in the Central Valley exceeds 105 degrees Fahrenheit.

(Continued)




(Continued)

11. NON-FIRM SERVICE PROGRAMS: (Cont’d.)

e. EMERGENCY CURTAILMENT PROCEDURE: When it becomes necessary for PG&E to request a curtailment, PG&E will notify the customer by telephone, electronic mail, or other reliable means of communication. This notification will designate a time by which the customer's kW demand is requested to be reduced to the customer's contractual firm service level.

The customer is requested not to resume the use of curtailed power until notified by PG&E that it may do so or until the customer has curtailed its service for six hours.

f. LIMIT ON EMERGENCY CURTAILMENTS: The number of curtailment events will not exceed one (1) per day, four (4) in a calendar week, and thirty (30) times per calendar year. The duration of the curtailment events will not exceed six (6) hours each, forty (40) hours per calendar month, and a total of one hundred (100) hours per calendar year. The customer will be given at least 30 minutes notice before each curtailment.

Automatic UFR operations shall not be included in the annual pre-emergency or emergency curtailment limit.

g. EMERGENCY-NOTICE PROVISION: If there is an emergency on the PG&E system, PG&E may ask the customer to curtail the use of electricity on less than the 30 minute notice allowed for the Non-Firm Service Option. The customer will be asked to make its best effort to comply. The customer will not be assessed the noncompliance penalty for failing to comply within the shorter notice period.

The customer will be assessed a noncompliance penalty if the regular notice period for the operation passes and the customer still has not curtailed use.

(N) | | |

(N) (T)

(D)

(D)

(Continued)


Revised Cal. P.U.C. Sheet No. 21025-E* Pacific Gas and Electric Company Cancelling Revised Cal. P.U.C. Sheet No. 15356-E San Francisco, California


(Continued)


h. NONCOMPLIANCE PENALTY:

The applicable noncompliance penalties are listed in Section 12. If a customer has curtailed to or below the designated firm service level for all of the requested pre-emergency and emergency curtailments, if any, in the preceding calendar year, the noncompliance penalty for the current year, will be the lower level shown in Section 12.

The penalty will be calculated by determining the total amount of excess energy taken during the curtailment period (energy taken in excess of the customer’s firm service level times the duration of the curtailment) and multiplying this total by the noncompliance penalty (per kWh).

Once a customer has complied with all the requested curtailments during the previous year, the customer's noncompliance penalty will remain at the reduced penalty level shown in Section 12 for the next calendar year. If the customer fails to comply with a requested curtailment, the noncompliance penalty for the following year will be the higher value shown in Section 12.

If no emergency or pre-emergency curtailments are called during a given year, the customer's noncompliance penalty for the next year in which curtailments occur shall be based on the customer's level of compliance during the last year curtailments were called.

During the year, PG&E will record any energy taken in excess of the customer's firm service level during any emergency or pre-emergency curtailments. PG&E will notify the customer of the amount of excess energy taken and the estimated noncompliance penalty. PG&E shall assess the noncompliance penalties, subject to the noncompliance penalty limit described below, at the end of the calendar year. The customer's noncompliance penalty shall be equal to the appropriate noncompliance penalty shown in Section 12 times the total amount of excess energy taken during any pre-emergency and emergency curtailments.

In any given calendar year, the noncompliance penalties may not exceed 200 percent of the annual incentive level. The noncompliance penalty limit is equal to twice the annual incentive paid (the difference between what the customer would have paid on firm service rates less the customer's bill on non-firm rates excluding noncompliance penalties). If a customer's total noncompliance penalties in any given year exceed the noncompliance penalty limit, PG&E shall bill the customer a noncompliance penalty equal to the noncompliance penalty limit.

(T)

(N) | |

(N)

(D)

(D)

(Continued)


Revised Cal. P.U.C. Sheet No. 22114-E Pacific Gas and Electric Company Cancelling Revised Cal. P.U.C. Sheet No. 21026, San Francisco, California 21379-E


(Continued)


i. ADDITIONAL NON-FIRM SERVICE PROVISIONS:

1) Required Re-Designations of Firm Service Level: A non-firm service customer must maintain a difference of at least 500 kW between the firm service level and the average monthly summer peak-period demand. If the difference is less than 500 kW for any three summer months during any 12-month period, the customer must designate a new firm service level. This new firm service level must be at least 500 kW below the lowest of the customer's average peak-period demands for the last six summer billing months preceding the new designation. If the customer cannot meet this requirement, PG&E will change the account to firm service.

2) Optional Re-Designations of Firm Service Level: A non-firm service customer may decrease the firm service level effective with the start of any billing month, provided the customer gives PG&E at least 30 days' written notice. The customer may increase the firm service level (or return to full service) only with PG&E's permission or by giving PG&E three years notice, or by giving such notice to PG&E during a one-month period following any revisions of the program operating criteria initiated by the ISO, or during an annual contract review period that is provided for between November 1 and December 1 each year. The increased firm service level must be such that there is still at least a 500-kW difference between the firm service level and the lowest average monthly summer peak-period demand. The increased firm service level will become effective with the first regular reading of the meter after the customer receives permission from PG&E or at the end of the three year notice period. If a customer elects to change to firm service, they will not be permitted to subsequently return to non-firm status in the future.

3) Telephone Line Requirements: Non-firm customers are required to make available a telephone line and space for a notification printer. This requirement is in addition to any other equipment requirement which may apply.

j. BILL REDUCTIONS FOR NON-FIRM SERVICE CUSTOMERS:

1) Demand Charges: Reduced peak-period demand charges for curtailable service shall be applied to the difference between the customer's maximum demand in the peak-period and its Firm Service Level (but not less than zero). The peak-period charges for firm service shall be applied to the peak-period demand less the above difference.

2) Energy Charges: Reduced energy charges for curtailable service shall be applied to (a-b), where (a) is the number of kilowatt-hours used in the time period and (b) is the product of the Firm Service Level and the number of hours in the time period. (a-b) shall not be less than zero.

(Continued)


Revised Cal. P.U.C. Sheet No. 15358-E* Pacific Gas and Electric Company Cancelling Revised Cal. P.U.C. Sheet No. 14225-E San Francisco, California


(Continued)


k. PROVISIONS SPECIFIC TO UFR PROGRAM:

1) Details on Automatic Interruptions: If a customer is participating in the UFR program, service to the customer will be automatically interrupted if the frequency on the PG&E system drops to 59.65 hertz for 20 cycles. PG&E will install and maintain a digital underfrequency relay and whatever associated equipment it believes is necessary to carry out such automatic interruption. Relays and other equipment will remain the property of PG&E. If more than one relay is required, PG&E will provide the additional relays as "special facilities," at customer's expense, in accordance with Section I of Rule 2.

In addition to the underfrequency relay, PG&E may install equipment that would automatically interrupt service in case of voltage reductions or other operating conditions.

2) Metering Requirements for UFR Program: If a customer is participating in the UFR program under Schedule E-20 in combination with firm or curtailable-only service, the customer will be required to have a separate meter for the UFR service. PG&E will provide the meter sets, but the customer will be responsible for arranging customer's wiring in such a way that the service for each account can be provided and metered at a single point. NOTE: Any other additional facilities required for a combination of curtailable with firm service will be treated as "special facilities" in accordance with Section I of Rule 2.

3) Communication Channel for UFR Service: UFR program customers are required to provide an exclusive communication channel from the PG&E-provided terminal block at the customer's facility to a PG&E-designated control center. The communication channel must meet PG&E's specifications, and must be provided at the customer's expense. PG&E shall have the right to inspect the communication circuit upon reasonable notice.

(Continued)

Advice Letter No. 1692-E-D Issued by Date Filed January 28, 1998 Decision No. 97-08-056 Thomas E. Bottorff Effective January 1, 1998 Vice President Resolution No. E-3510 26292 Rates & Account Services

Revised Cal. P.U.C. Sheet No. 21027-E Pacific Gas and Electric Company Cancelling Original Cal. P.U.C. Sheet No. 20513-E San Francisco, California


(Continued)


l. INTERACTIONS WITH OTHER DEMAND RESPONSE PROGRAMS:

1. Customers who participate in a third-party sponsored interruptible load program must immediately notify PG&E of such activity.

2. Participants in the non-firm program may also participate in the Demand Bidding Program (Schedule E-DBP), but will not be paid the energy reduction incentives under the Schedule E-DBP during those hours where a non-firm event is issued.

3. Participants in the non-firm program may participate in the Optional Binding Mandatory Curtailment Program (Schedule E-OBMC) and the Pilot Optional Binding Mandatory Curtailment Program (Schedule E-POBMC) subject to meeting all applicable eligibility, operational and participation requirements specified in those schedules.

4. Participants in the non-firm program may participate in the Call Option of the California Power Authority Demand Reserves Partnership (CPA-DRP) program provided the additional load committed to the CPA-DRP is below their Firm Service Level (FSL) under the non-firm program. Participants in the non-firm program may participate in the Supplemental Energy Market Option of the CPA-DRP program, but will not be paid for curtailments under the California Power Authority’s program during those hours when a non-firm event is issued. Participants in the non-firm program may not participate in the Ancillary Service Option of the CPA-DRP program.

5. Participants on the non-firm program shall not participate in the Scheduled Load Reduction Program (Schedule E-SLRP), or the Critical Peak Pricing Program (Schedule E-CPP) while on the non-firm program. Participants on the non-firm program may participate in the Base Interruptible Program (Schedule E-BIP) only after they have completed their annual obligations under the non-firm program.

(T)

(N) | | | |

(N)

(D)

(Continued)




(Continued)

12. NON-FIRM SERVICE RATES:

These rates are applicable if the customer elects to take non-firm service. See Section 11 for an explanation of the non-firm service program and eligibility criteria.

Total bundled service charges for non-firm service are calculated using the total rates shown below. Direct Access (DA) and Community Choice Aggregation (CCA) charges shall be calculated in accordance with the paragraph in this rate schedule titled Billing.

TOTAL RATES

Total Customer Charge Rates Secondary



Nonfirm Customer Charge ($ per meter per day) $18.89117 $16.42710 $29.73306 Nonfirm w/UFR Customer Charge ($ per meter per day) $19.21971 $16.75564 $30.06160 Optional Meter Data Access Charge $ 0.98563 $ 0.98563 $ 0.98563

Total Demand Rates ($ per kW)

Maximum Peak Demand Summer $5.50 (R) $3.63 (R) ($0.62) (R) Maximum Part-Peak Demand Summer $3.11 | $2.00 | $0.05 | Maximum Demand Summer $3.08 | $3.09 | $0.75 | Maximum Part-Peak Demand Winter $3.06 | $2.00 | $0.19 | Maximum Demand Winter $3.08 (R) $3.09 (R) $0.75 (R)

Total Energy Rates ($ per kWh)

Peak Summer $0.13478 (R) $0.10823 (R) $0.10034 (R) Part-Peak Summer $0.08248 | $0.07228 | $0.06667 | Off-Peak Summer $0.07550 | $0.07058 | $0.06424 | Part-Peak Winter $0.08787 | $0.07964 | $0.07591 | Off-Peak Winter $0.07531 (R) $0.07133 (R) $0.06721 (R) Noncompliance Penalty ($ per kWh per event) $8.40 $8.40 $8.40 Noncompliance Penalty ($ per kWh per event)

(For customers who fully complied with the previous years operation)

$4.20 $4.20 $4.20

UFR Credit ($ per kWh, if applicable) $0.00091 $0.00091 $0.00091 Total bundled service charges shown on customers’ bills are unbundled according to the component rates shown below.

UNBUNDLING OF TOTAL RATES

Customer Charge Rates: Customer charge rates provided in the Total Rate section above are assigned entirely to the unbundled distribution component.

Demand Rates by Component ($ per kW)

Generation: Maximum Peak Demand Summer $7.07 (R) $8.21 (R) $6.88 (R) Maximum Part-Peak Demand Summer $1.95 | $1.83 | $0.55 | Maximum Demand Summer ($3.68) | ($2.62) | ($3.87) | Maximum Part-Peak Demand Winter $1.92 | $1.83 | $0.69 | Maximum Demand Winter ($3.68) (R) ($2.62) (R) ($3.87) (R) Distribution: Maximum Peak Demand Summer ($1.57) ($4.58) ($7.50) Maximum Part-Peak Demand Summer $1.16 $0.17 ($0.50) Maximum Demand Summer $2.14 $1.09 $0.00 Maximum Part-Peak Demand Winter $1.14 $0.17 ($0.50) Maximum Demand Winter $2.14 $1.09 $0.00 Transmission Maximum Demand* $2.44 $2.44 $2.44 Reliability Services Maximum Demand* $2.18 $2.18 $2.18 _______________


(Continued)



COMMERCIAL/INDUSTRIAL/GENERAL SCHEDULE E-20— SERVICE TO CUSTOMERS WITH MAXIMUM DEMANDS OF 1,000 KILOWATTS OR MORE

(Continued)

12. NON-FIRM SERVICE RATES: (Cont’d.)

UNBUNDLING OF TOTAL RATES (Cont’d.)

Energy Rate by Components ($ per kWh) Secondary



Generation: Peak Summer $0.11410(R) $0.09835 (R) $0.09558 (R) Part-Peak Summer $0.05532 | $0.05216 | $0.05085 | Off-Peak Summer $0.04952 | $0.05058 | $0.04842 | Part-Peak Winter $0.05981 | $0.05898 | $0.06009 | Off-Peak Winter $0.04936 (R) $0.05129 (R) $0.05139 (R) Distribution: Peak Summer $0.00136 ($0.00830) ($0.01220) Part-Peak Summer $0.00784 $0.00194 ($0.00114) Off-Peak Summer $0.00666 $0.00182 ($0.00114) Part-Peak Winter $0.00874 $0.00248 ($0.00114) Off-Peak Winter $0.00663 $0.00186 ($0.00114)

Noncompliance Penalty ($ per kWh per event) $8.40 $8.40 $8.40 Noncompliance Penalty ($ per kWh per event)

(For customers who fully complied with the previous years operation)

$4.20 $4.20 $4.20

UFR Credit ($ per kWh, if applicable) $0.00091 $0.00091 $0.00091 Transmission Rate Adjustments* (all usage) $0.00016 (I) $0.00016 (I) $0.00016 (I) Public Purpose Programs (all usage) $0.00454 $0.00402 $0.00326 Nuclear Decommissioning (all usage) $0.00035 $0.00035 $0.00035 Competition Transition Charge (all usage) $0.00434 $0.00372 $0.00326 Energy Cost Recovery Amount (all usage) $0.00534 $0.00534 $0.00534 DWR Bond (all usage) $0.00459 (R) $0.00459 (R) $0.00459 (R)

_______________


(Continued)




(Continued)

13. CONTRACTS: STANDARD SERVICE AGREEMENT: To begin service under Schedule E-20, the customer shall be required to sign PG&E’s Electric General Service Agreement (GSA). The GSA has an initial term of three (3) years. Once the three-year initial term is over, the agreement will automatically continue in effect for successive terms of one year each until it is cancelled. Customers may, at any time, request PG&E to modify the GSA if the service arrangements, electrical demand requirements, or delivery criteria to its premises change. However, customers will still be obligated to perform the terms and conditions outlined in any other agreements that supplement the GSA.

14. BILLING: A customer’s bill is calculated based on the option applicable to the customer.

Bundled Service Customers receive supply and delivery services solely from PG&E. The customer’s bill is based on the Total Rates and Conditions set forth in this schedule.

Transitional Bundled Service Customers take transitional bundled service as prescribed in Rules 22.1 and 23.1, or take bundled service prior to the end of the six (6) month advance notice period required to elect bundled portfolio service as prescribed in Rules 22.1 and 23.1. These customers shall pay charges for transmission, transmission rate adjustments, reliability services, distribution, nuclear decommissioning, public purpose programs, the FTA (where applicable), the RRBMA (where applicable), the applicable Cost Responsibility Surcharge (CRS) pursuant to Schedule DA CRS or Schedule CCA CRS, and short-term commodity prices as set forth in Schedule TBCC.

Direct Access (DA) and Community Choice Aggregation (CCA) Customers purchase energy from their non-utility provider and continue receiving delivery services from PG&E. Bills are equal to the sum of charges for transmission, transmission rate adjustments, reliability services, distribution, public purpose programs, nuclear decommissioning, the FTA (where applicable), the RRBMA (where applicable), the franchise fee surcharge, and the applicable CRS. The CRS is equal to the sum of the individual charges set forth below. Exemptions to the CRS are set forth in Schedules DA CRS and CCA CRS.

DA CRS Secondary



Energy Cost Recovery Amount Charge (per kWh) $0.00534 $0.00534 $0.00534 DWR Power Charge (per kWh) $0.01273 (I) $0.01335 (I) $0.01381 (I) DWR Bond Charge (per kWh) $0.00459 (R) $0.00459 (R) $0.00459 (R) CTC Rate (per kWh) $0.00434 $0.00372 $0.00326 Total DA CRS (per kWh) $0.02700 $0.02700 $0.02700

CCA CRS Secondary



Energy Cost Recovery Amount Charge (per kWh) $0.00534 $0.00534 $0.00534 DWR Power Charge (per kWh) $0.01566 $0.01628 $0.01674 DWR Bond Charge (per kWh) $0.00459 (R) $0.00459 (R) $0.00459 (R) CTC Rate (per kWh) $0.00434 $0.00372 $0.00326 Total CCA CRS (per kWh) $0.02993 (R) $0.02993 (R) $0.02993 (R)

(Continued)




(Continued)

15. CARE DISCOUNT FOR NONPROFIT GROUP-LIVING AND SPECIAL EMLOYEE HOUSING FACILITIES:

Facilities which meet the eligibility criteria in Rule 19.2 or 19.3 are eligible for a California Alternate Rates for Energy discount under Schedule E-CARE. CARE customers are exempt from paying the DWR Bond Charge. For CARE customers, no portion of the rates shall be used to pay the DWR bond charge. Generation is calculated residually based on the total rate less the sum of the following: Transmission, Transmission Rate Adjustments, Reliability Services, Distribution, Public Purpose Programs, Nuclear Decommissioning, Competition Transition Charge (CTC), Energy Cost Recovery Amount, FTA and the Rate Reduction Bond Memorandum Account Rate.

(T)

16. OPTIONAL OPTIMAL BILLING PERIOD SERVICE:

The Optimal Billing Period service is an experimental program that is limited to a maximum of 150 bundled service accounts at any one time. Customers electing this optional service must sign the Optimal Billing Service Customer Election Form (Standard Form 79-842).

a. Eligibility

On an experimental pilot basis and subject to the availability and installation of solid state recorder equipment, firm service primary and secondary voltage customers whose maximum demand exceeds 1,000 kW for three consecutive billing months may select the “optimal billing period” service on a voluntary basis in up to two “subject” months (subject month is defined as the month in which the production cycle starts or ends), one at the start and one at the end of the customer’s high seasonal production cycle. The meter read date separating the subject month at the start of production, but precedes it at the end of production) would be redesignated to an alternative read date. In no event shall any revised billing period exceed 45 days nor less than 15 days. Where the start date is in a summer month, the summer season average rate limiter must otherwise apply to the subject month at the start of the customer’s high production cycle, but need not apply to the subject month at the end of production or the two adjacent months. The customer would retain the protection of the summer average rate limiter in all summer months, including the revised subject and adjacent months, where the rate limiter is imposed before the additional customer charge in Section 18.c has been included in the calculation.

To qualify, the duration of the customer’s high seasonal production period must be six (6) months or less, and the customer’s energy consumption during its high seasonal production cycle must be at least 2.0 times its consumption during its low seasonal production cycle for the most recent twelve (12) month period. Customers that discontinue this option may not enroll in this option again for a period of twelve (12) months. The customer must also specify which six (6) consecutive calendar months will be the optimal billing period. The optimal billing period must encompass the customer’s high seasonal production period.

(Continued)

Advice Letter No. 2626-E-B Issued by Date Filed February 25, 2005 Decision No. 04-11-015 Karen A. Tomcala Effective March 1, 2005 Vice President Resolution No. 54422 Regulatory Relations



(Continued)

16. OPTIONAL OPTIMAL BILLING PERIOD SERVICE: (Cont’d.)

b. Customer Notification to PG&E

Upon enrollment, the customer shall notify PG&E of the approximate two months where seasonal production starts and ends. As they occur, the customer shall notify PG&E of the exact seasonal production start and end dates. Upon notification by the customer of a production start date during a summer month, PG&E will wait until the regular read date to verify that the regular subject month bill would have otherwise invoked the rate limiter. If the rate limiter is invoked for the summer subject start month, the customer will be billed based on the optimal meter read dates or the regular scheduled meter read dates, whichever is the lower bill. Throughout the six month period, customers will receive their regular bill. Approximately two months after the production start or end date, the customer will receive a credit, if one should apply, for the optimal billing period. If a credit does not apply, the customer will not receive additional billing. If the rate limiter does not otherwise apply, the regular bill based on the old read date will be issued, and the customer can then request the special optimal bill option in only one production end date "subject" month. The application of this billing option to a production end date may occur prior to its application to a production start date, such as when a customer has more than one high production cycle. The customer must notify PG&E in writing, via facsimile (fax) to both the PG&E account representative and PG&E's Customer Billing Department, of the production start or end date within two days of the production start or end date. Customers will receive from PG&E's Customer Billing Department a fax receipt verification upon notice of a production start or end date. PG&E will notify the customer of the regularly scheduled meter read dates and, upon request, the customer's rate limiter history.

c. Customer Charge

Upon enrollment, a special customer charge will be assessed in all six (6) months in the optimal billing period to cover the incremental costs of the required solid state recorder, special program billing, recruitment, and administrative costs. The customer charge shall be $130 per meter per optimal billing period month for primary and secondary voltage customers. The customer is obligated to pay this monthly customer charge upon only while enrolled in this option, but any customer that drops out may not enroll in this option for a period of twelve (12) months. Customers who have signed contracts and are awaiting solid state recorders so that they can participate in the program will not be assessed the special customer charge until a solid state recorder has been installed.

For billing purposes, the special customer charge for the optional billing period service shall be assigned to Distribution.

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(Continued)

Advice Letter No. 2013-E Issued by Date Filed June 29, 2000 Decision No. DeAnn Hapner Effective August 8, 2000 Vice President Resolution No. 42269 Regulatory Relations



(Continued)

16. OPTIONAL OPTIMAL BILLING PERIOD SERVICE: (Cont’d.)

d. Proration of Charges

All applicable customer charges, demand charges or other applicable fixed charges, shall be prorated as specified in Rule 9. As specified in Rule 9, Sections A and B, the regular billing period will be once each month, and prorations for monthly bills of less than 27 or more than 33 days shall be calculated on the basis of the number of days in the period in question to the total number of days in an average month, as specified in Rule 9.

e. Functional Assignment of Credit

For billing purposes, the optional billing credit will be assigned to Distribution.

17. ELECTRIC EMER-GENCY PLAN ROTATING BLOCK OUTAGES:

As set forth in CPUC Decision 01-04-006, all transmission level customers except essential use customers, OBMC participants, net suppliers to the electrical grid, or others exempt by the Commission, are to be included in rotating outages in the event of an emergency. A transmission level customer who refuses or fails to drop load shall be added to the next rotating outage group so that the customer does not escape curtailment. If the transmission level customer fails to cooperate and drop load at PG&E's request, automatic equipment controlled by PG&E will be installed at the customer’s expense per Electric Rule 2. A transmission level customer who refuses to drop load before installation of the equipment shall be subject to a penalty of $6/kWh for all load requested to be curtailed that is not curtailed. The $6/kWh penalty shall not apply if the customer’s generation suffers a verified, forced outage and during times of scheduled maintenance. The scheduled maintenance must be approved by both the ISO and PG&E, but approval may not be unreasonably withheld.

18. STANDBY APPLICA-BILITY:

SOLAR GENERATION FACILITIES EXEMPTION: Customers who utilize solar generating facilities which are less than or equal to one megawatt to serve load and who do not sell power or make more than incidental export of power into PG&E’s power grid and who have not elected service under Schedule E-NET, will be exempt from paying the otherwise applicable standby reservation charges.

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DISTRIBUTED ENERGY RESOURCES EXEMPTION: Any customer under a time-of-use rate schedule using electric generation technology that meets the criteria as defined in Electric Rule 1 for Distributed Energy Resources is exempt from the otherwise applicable standby reservation charges. Customers qualifying for this exemption shall be subject to the following requirements. Customers qualifying for an exemption from standby charges under Public Utilities (PU) Code Sections 353.1 and 353.3, as described above, must take service on a time-of-use (TOU) schedule in order to receive this exemption until a real-time pricing program, as described in PU Code 353.3, is made available. Once available, customers qualifying for the standby charge exemption must participate in the real-time program referred to above. Qualification for and receipt of this distributed energy resources exemption does not exempt the customer from metering charges applicable to time-of-use (TOU) and real-time pricing, or exempt the customer from reasonable interconnection charges, non-bypassable charges as required in Preliminary Statement BB - Competition Transition Charge Responsibility for All Customers and CTC Procurement, or obligations determined by the Commission to result from participation in the purchase of power through the California Department of Water Resources, as provided in PU Code Section 353.7.

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(Continued)

Advice Letter No. 2439-E Issued by Date Filed November 14, 2003 Decision No. Karen A. Tomcala Effective December 24, 2003 Vice President Resolution No. 49605 Regulatory Relations



(Continued)

19. DWR BOND CHARGE:

The Department of Water Resources (DWR) Bond Charge was imposed by California Public Utilities Commission Decision 02-10-063, as modified by Decision 02-12-082, and is property of DWR for all purposes under California law. The Bond Charge applies to all retail sales, excluding CARE and Medical Baseline sales. The DWR Bond Charge (where applicable) is included in customers' total billed amounts.

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(Continued)


Pacific Gas and Electric Company Industrial/General Service Electric Rates at a Glance (E20 S, P, and T)

For Services > 1,000 kW Demand

Rates Effective: June 1, 2005, to Present

Rate Schedule Customer Charge Season Time-of-Use

PeriodDemand Charges

(per kW)Energy Charges1/

(per kWh)Average Rate Limiter

(per kWh)

Peak Period Rate Limiter

(per kWh)

UFR Credit2/

(per kWh)

"Average" Total Rate3/

(per kWh)

On Peak $13.00 $0.14725 $0.97708 Part-Peak $3.61 $0.08380 -Off-Peak - $0.07682 -

Maximum $3.08 - -Part-Peak $3.56 $0.08919 Off-Peak - $0.07663 - - -

Maximum $3.08 -On Peak $11.13 $0.12070 $0.84876

Part-Peak $2.50 $0.07360 -Off-Peak - $0.07190 -


Maximum $3.09 -On Peak $6.88 $0.11281 $0.55750

Part-Peak $0.55 $0.06799 -Off-Peak - $0.06556 -


Maximum $0.75 -On Peak $5.50 $0.13478 ($0.00091)

Part-Peak $3.11 $0.08248 ($0.00091)Off-Peak - $0.07550 ($0.00091)

Maximum $3.08 - -Part-Peak $3.06 $0.08787 ($0.00091)Off-Peak - $0.07531 - - ($0.00091)

Maximum $3.08 - -On Peak $3.63 $0.10823 ($0.00091)



Maximum $3.09 - -On Peak ($0.62) $0.10034 ($0.00091)



Maximum $0.75 - -

1/Energy Charges include Economic Stimulus Rate Credit of $0.00432/kWh.2/Applicable only to Interruptible service, see tariff for full description of Curtailable and Interruptible service option. To obtain Curtailable service rates, remove the UFR credit from the 'Energy Charges' column.3/Based on estimated forecast. Average rates provided only for general reference, and individual customer's average rate will depend on its applicable kW, kWh, and TOU data.4/Noncompliance Penalty (per kWh per event) = $8.40 and for customers who fully complied with previous year's operations = $4.20. Nonfirm enrollment is closed to existing customers, but open to qualifying

new customers and new load for existing customers. See tariff for further details.Note: Summer Season: May-October Winter Season: November-April

This table provided for comparative purposes only. See current tariffs for full information regarding rates, application, eligibility and additional options.

Summer

Winter

Summer

Winter

Summer

Winter

Summer

Winter

Summer

Winter

Summer

Winter

E20 Secondary

Firm

E20 Primary

Firm

$12.64887 per day

$10.18480 per day

-

-

E20 Primary

NonFirm4/

(applicability is limited)

E20 Transmission

NonFirm4/


$16.42710 per meter per day;

$16.75564 per meter per day with

UFR



UFR

$23.49076 per day



UFR

E20 Transmission

Firm

E20 Secondary NonFirm4/


-

-

$0.12036

$0.10412

$0.08451

$0.10824

$0.09702

$0.07400

$0.13995

$0.13995

-

-

-

-

-

-


SCHEDULE E-BIP—BASE INTERRUPTIBLE PROGRAM

APPLICABILITY: This schedule is available until modified or terminated in the rate design phase of the next general rate case or similar proceeding as ordered in Decision 02-04-060. The E-BIP Program (Program) is intended to provide load reductions on PG&E’s system on a day-of basis when the California Independent System Operator (CAISO) issues a curtailment notice. Customers enrolled in the Program will be required to reduce their load down to their firm service level within thirty (30) minutes of their notice from PG&E. This program may be closed by PG&E without notice when the interruptible program limits set forth in CPUC Decision 01-04-006 and Rulemaking 00-10-002 have been fully subscribed.

TERRITORY: This schedule applies everywhere PG&E provides service.

ELIGIBILITY: This schedule is available to both bundled-service and Direct Access commercial, industrial, and agricultural customers. Each customer must take service under the provisions of a demand time-of-use rate schedule to participate in the Program and have at least an average monthly demand of 100 kilowatt (kW). Customers being served under Schedules AG-R or AG-V are not eligible for this program. Customers taking service under Direct Access must meet the metering requirements prescribed in the Metering Equipment section of this rate schedule.

Customers must submit a Demand Response Program Agreement (Form 79-976), and a Customer Agreement and Password Agreement Governing use of Internet-Based Software Agreement (Form 79-977), in order to establish service. In addition, customers must have the required metering and notification equipment in place prior to participation in the Program.

A customer must designate the number of kW (“firm service level”) to which it will reduce its load down to or below during a Program operation in Form 79-976. The designated firm service level must be no more than eighty-five percent (85%) of the customer’s highest monthly maximum demand during the summer on–peak and winter partial-peak periods over the past 12 months with a minimum load reduction of 100 kW. If load information is unavailable, customers must demonstrate to PG&E’s satisfaction that they can meet these minimum requirements.

Customers on this program may not have, or obtain, any insurance for the purpose of paying non-compliance penalties for willful failure to comply with requests for curtailments. Customers with such policy will be terminated from the Program, and will be required to pay back any incentives that the customer received for the period covered by the insurance. If the period cannot be determined, the recovery shall be for the entire period the customer was on the program.

Customers who are deemed essential under the Electric Emergency Plan as adopted in Decision 01-04-006 and Rulemaking 00-10-002, must submit to PG&E a written declaration that states that the customer is, to the best of that customer’s understanding, an essential customer under Commission rules and exempt from rotating outages. It must also state that the customer voluntarily elects to participate in an interruptible program for part or all of its load based on adequate backup generation or other means to interrupt load upon request by the respondent utility, while continuing to meet its essential needs. In addition, an essential customer may commit no more than 50% of its average peak load to interruptible programs.

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(N)

(D)

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(Continued)

Advice Letter No. 2623-E Issued by Date Filed February 7, 2005 Decision No. Karen A. Tomcala Effective March 19, 2005 Vice President Resolution No. 53861 Regulatory Relations


SCHEDULE E-BIP—BASE INTERRUPTIBLE PROGRAM (Continued)

METERING EQUIPMENT:

Each account must have an interval meter capable of recording usage in 15-minute intervals installed that can be read remotely by PG&E. A Meter Data Management Agent (MDMA) may also read the customer’s meter on behalf of the customer’s Energy Service Provider (ESP), if a customer is receiving Direct Access Service. Metering equipment (including telephone line, cellular, or radio control communication device) must be in operation for at least ten (10) days prior to participating in the program. If required, PG&E will provide and install the metering equipment at no cost to the bundled service customer. The installation of an internal data meter for customers taking service under the provisions of Direct Access is the responsibility of the customer’s Energy Service Provider, or their Agent, and must be installed in accordance with Electric Rule 22.

Customers receiving an interval meter at no charge from PG&E through this Program will be able to continue to use it at no additional cost even after the Program is terminated, provided that the customer remained in the Program continuously for a minimum period of one year. A customer who receives an interval meter through this Program but later elects to leave the Program prior to the one-year anniversary date, or is terminated for cause, will reimburse PG&E for all expenses associated with the installation and maintenance of the meter. Such charges will be collected as a one-time payment pursuant to Electric Rule 2, Section I.

Direct Access Service Customers – If PG&E is the Meter Data Management Agent (MDMA) on behalf of the customer’s Energy Service Provider, no additional fees will be required from the Direct Access service customer. On the other hand, if the Direct Access service customer uses a third-party MDMA, the customer will be responsible for any and all costs associated with providing the interval data into the PG&E system on a daily basis. This includes any additional metering or communication devices that may need to be installed and any additional fees assessed by the customer’s ESP. Prior to customer’s participation in the program, the customer must be able to successfully transfer meter data within PG&E’s specification on a daily basis for a period of no less than ten (10) days to establish their baseline.

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(T)

(N)| |

(N) (D)

(N) | | | | | | | |

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(T)

NOTIFICATION EQUIPMENT:

Customers, at their expense, must have access to the Internet and an e-mail address to receive notification via the Internet. In addition, all customers must have, at their expense, an alphanumeric pager that is capable of receiving a text message sent via the Internet. A customer cannot participate in the Program until all of these requirements have been satisfied.

• In the event of a Program curtailment operation, customers will be notified using one or more of the above-mentioned systems. Receipt of such notice is the responsibility of the participating customer. Once notified, the customer must log into the Program’s Internet web site and acknowledge participation in the curtailment operation. Failure to acknowledge a curtailment notice does not release the customer from its obligation to participate. PG&E does not guarantee the reliability of the pager system, e-mail system or Internet site by which the customer receives notification.

(T)

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(D)

(Continued)




INCENTIVE PAYMENTS:

PG&E will evaluate and credit customers and/or apply non-compliance penalties for the customer load reductions realized under Schedule E-BIP within a period no longer than ninety (90) days after each curtailment event, depending on where the curtailment event falls within the customer’s actual billing cycle. The incentive payments will be reflected in the customer’s regular monthly bill as an adjustment.

During the Summer Season (May 1 through October 31) payments will be paid based on the difference of the customer’s average monthly on-peak period demand and its designated firm service level. During the Winter Season (November 1 through April 30) payments will be paid based on the difference of the customer’s average monthly partial-peak period demand and its designated firm service level. This difference will be multiplied by the price of $7.00 per kW-month to determine the incentive payment.

FAILURE TO REDUCE LOAD

Customers will be penalized $6.00 per kWh for energy usage over its firm service level during a curtailment. PG&E may elect to evaluate and assess the non-compliance penalties associated with several curtailment events as a single adjustment.

INTERACTION WITH CUSTOMER’S OTHER APPLICABLE CHARGES:

Participating customers’ regular electric service bills will continue to be calculated each month based on their actual recorded monthly demands and energy usage.

Customers who participate in a California Power Authority (CPA) or a third party sponsored interruptible load program must immediately notify PG&E of such activity.

Load can only be committed to one interruptible program for any given hour of a curtailment, and customers will be paid for performance under only one program for a given load reduction.

Customers may participate in the Optional Binding Mandatory Curtailment Plan (Schedule E-OBMC), and the Pilot Optional Binding Mandatory Curtailment Plan (Schedule E-POBMC). With limitations, participants in E-BIP may also participate in the Non-Firm Program, Demand Bidding Program (Schedule E-DBP), and the California Power Authority Demand response Program (CPA DRP). Customers currently enrolled in Non-Firm program, must complete all annual obligations to that program before being eligible for E-BIP. Customers enrolled in E-DBP will not receive an incentive payment during hours where there is an overlapping E-BIP event. Customers may participate in the CPA-DRP provided their CPA-DRP interruptible load is below their E-BIP Firm Service Level.

Customers shall not participate in the Schedule Load Reduction Program (Schedule E-SLRP) or the Critical Peak Pricing Program (Schedule E--CPP) while on the E-BIP program.

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(T)

(Continued)

Advice Letter No. 2389-E Issued by Date Filed June 16, 2003 Decision No. 03-06-032 Karen A. Tomcala Effective August 1, 2003 Vice President Resolution No. 48455 Regulatory Relations

Original Cal. P.U.C. Sheet No. 22850-E Pacific Gas and Electric Company Cancelling Cal. P.U.C. Sheet No. San Francisco, California


PROGRAM DETAILS:

A. Program Options

Customers participating in the program must elect one of the two options below which shall be designated on their Demand Response Program Agreement (Form 79-976). Customers who participate in E-BIP prior to January 27, 2005, will be automatically defaulted to Option A.

OPTION A

1. Notification Period – Customers will be given at least thirty (30) minutes notice before each curtailment.

2. Event Limits – A Program curtailment operation will be limited to a maximum of one (1) event per day and four (4) hours per event. The Program will not exceed ten (10) events during a calendar month, or one hundred twenty (120) hours per calendar year.

3. Program Participation Incentive Payments – A $7.00/kW incentive payment will be paid on a monthly basis based on the customer’s monthly potential load reduction amount.

4. Failure to Reduce Loads during an Event – Customers will be penalized $6.00 per kilowatt-hour (kWh) for energy usage over its firm service level during a curtailment.

OPTION B

1. Notification Period – Customers will be given at least three (3) hours notice before each curtailment.

2. Event Limits – A Program curtailment operation will be limited to a maximum of one (1) event per day and three (3) hours per event. The Program will not exceed ten (10) events during a calendar month, or ninety (90) hours per calendar year.

3. Program Participation Incentive Payments – A $3.00/kW incentive payment will be paid on a monthly basis based on the customer’s monthly potential load reduction amount.

4. Failure to Reduce Loads during an Event – Customers will be penalized $2.50 per kWh for energy usage over its firm service level during a curtailment.

B. Other Program Guidelines

1. E-BIP Events – The CAISO, based on its forecasted system conditions and operating procedures, may request PG&E to operate all or part of the customers on the Program. The Program may also be operated in the event of a transmission system contingency.

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(N)

(Continued)


Original Cal. P.U.C. Sheet No. 22851-E Pacific Gas and Electric Company Cancelling Cal. P.U.C. Sheet No. San Francisco, California


PROGRAM DETAILS: (Cont’d.)

B. Other Program Guidelines (Cont’d.)

2. Potential Load Reduction – Participants monthly potential load reduction amount during the Summer Season (May 1 through October 31) will be paid based on the difference of the customer’s average monthly on-peak period demand (on-peak kWh divided by available on-peak hours) and its designated firm service level. During the Winter Season (November 1 through April 30) payments will be paid based on the difference of the customer’s average monthly partial-peak period demand (partial-peak kWh divided by available partial-peak hours) and its designated firm service level. This difference will be multiplied by the appropriate incentive level to determine the monthly incentive payment.

3. PG&E will evaluate and credit customers and/or apply non-compliance penalties for the customer load reductions realized under Schedule E-BIP within a period no longer than ninety (90) days after each curtailment event, depending on where the curtailment event falls within the customer’s actual billing cycle. The incentive payments will be reflected in the customer’s regular monthly bill as an adjustment.

4. PG&E may elect to evaluate and assess the non-compliance penalties associated with several curtailment events as a single adjustment.

5. Customers may re-designate their firm service level or discontinue participation in the Program only once each year during the month of November. Customers shall provide written notification of such changes to PG&E. Cancellation will become effective with the first regular billing cycle following the thirty (30) days’ notice.

6. The Program will be operated throughout the year.

7. In the event of a curtailment event, customers on the Program will be notified as described in the Notification Equipment Section of this schedule.

8. PG&E reserves the right to terminate the Program, with Commission approval and thirty (30) days’ written notice to customers.

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(N)

(Continued)




(D)

INTERACTION WITH CUSTOMER’S OTHER APPLICABLE CHARGES:

Participating customers’ regular electric service bills will continue to be calculated each month based on their actual recorded monthly demands and energy usage.

Customers who participate in a California Power Authority (CPA) or a third party sponsored interruptible load program must immediately notify PG&E of such activity.

Load can only be committed to one interruptible program for any given hour of a curtailment, and customers will be paid for performance under only one program for a given load reduction.

Customers may participate in the Optional Binding Mandatory Curtailment Plan (Schedule E-OBMC), and the Pilot Optional Binding Mandatory Curtailment Plan (Schedule E-POBMC) but the customers’ Maximum Load Level under those programs may not overlap their FSL. With limitations, participants in E-BIP may also participate in the Non-Firm Program, Demand Bidding Program (Schedule E-DBP), and the California Power Authority Demand Response Program (CPA DRP). Customers currently enrolled in Non-Firm program, must complete all annual obligations to that program before being eligible for E-BIP. Customers participating in E-DBP, will not receive an incentive payment during hours where there is an overlapping E-BIP event. Customers may participate in the CPA-DRP provided their CPA-DRP interruptible load is below their E-BIP Firm Service Level.

Customers shall not participate in the Schedule Load Reduction Program (Schedule E-SLRP) or the Critical Peak Pricing Program (Schedule E-CPP) while on the E-BIP program.

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September 2005

H:\POSF\Report\Final_091205\Final\APPENDIX F.doc C-1

APPENDIX F

Responses to Comments on Draft Final Report for the PoSF Shoreside Power Feasibility Project, August 8, 2005

September 2005


Responses to General Comments by Bluewater on Draft Final Report for the PoSF Shoreside Power Feasibility Project

Question General Comments Responses Actions

1 It appears that the shoreside power study did not break-out and compare the dockside emissions produced by each ship per port call per type of emissions and the reductions that would be gained from shoreside power. Instead, the total emissions and shoreside power reductions seem to be based on a port call from 12.5 miles out to sea and back.

ENVIRON draft final report presented separately the hotelling (berthing or dockside) emissions and transit emissions by pollutant types per port call (Table 4-9) and annually (Table 4-10) from auxiliary engines for all ships, as well as shoreside emission estimates per port call (Table 4-11) and annually (Table 4-12) for the 4 selected candidate ships. Finally, the ENVIRON report also presented net shoreside power emission reduction estimates annually for the selected ships (Table 4-14). ENVIRON report didn't include transit emissions in the shoreside power emissions and emission reduction calculations.

To facilitate better comparison, ENVIRON revised Table 4-14, showing berthing emissions, shoreside power emission estimates, net shoreside power emission reduction estimates annually and per port call, as well as percent of shoreside emission reduction for the selected ships.

2 The CTEAC clearly wanted dockside to dockside emissions comparisons, along with any total emissions generated by each cruise ship per call. The CTEAC cannot move forward on any recommendations until the proper emissions information is provided as requested.

See response to Q1.

3 How did ENVIRON arrive at the conclusion (made in a recent PowerPoint presentation) that shoreside power provides only 50 percent emissions reductions at the dock when all other studies show closer to 90 or 100 percent?

The 50% emission reduction was estimated based on the potential shoreside power emissions reductions for the 4 selected ships over the total 2004 berthing emissions. For the selected ships, the emission reductions were calculated to be about 80% for NOx and PM (about 70% PM reduction for CRYSTAL because of the use of 0.2% low sulfur fuel.)

ENVIRON clarified/added discussions in Section 4 and Section 8 on percent shoreside emission reductions for the selected ships, and for the total 2004 berthing emissions.

4 Why does ENVIRON not show in the final report (only in the PowerPoint) the actual percentage reductions? It is very difficult to see or understand what the emissions reductions are in terms of percentage.

See response to Q3.

September 2005


Question General Comments Responses Actions 5 The report must include a

simple table that show the emissions of each vessel at the dock per day and the emissions reductions achieved at the dock per day when hooked up to shoreside power both in terms of tons (or pounds) and the percentage reduction. As presented it is unclear what the amount or percentage reduction is per ship call when hooked up to shoreside power.

See responses to Q1 and Q3.

6 Cost effectiveness should be considered both with and without infrastructure costs. Those costs may be subsidized by public agencies, the developers, the cruise lines, utilities or others. It would be helpful to compare just fuel to electricity. To be fair, if you include all the infrastructure for shoreside, then you must also include the cost of infrastructure for fueling including fuel tanks, hoses, labor costs to fuel, etc

Understanding that the cost may be subsidized, there still will be incremental costs to develop the shoreside power infrastructure and system. Our understanding is that there will be no refueling facility and services in the new cruise ship terminal. Table 7-1 presented separately the shipside operation costs for electricity and fuel that can be used to perform just fuel to electricity cost-effective analysis.

Issues/subjects have been discussed in many places of the report.

7 Emissions comparisons to the EIR estimates need to be reconciled. It appears to me that the estimates for hotelling emissions for the Crystal Harmony, for example, that appear in the appendix in the EIR are inconsistent with the ENVIRON study. This needs to be addressed, compared and reconciled.

Emission estimates from the ENVIRON report were different from those presented in the San Francisco Cruise Terminal Mixed-Use Project EIR because ENVIRON used the latest available marine engine emission factors (very similar to those used to develop PoLA and PoLB emission inventories for marine vessels, and POLB Cold Ironing Study), and the EIR used dated emission factors from a 1999 report (Acurex, 1999). In addition, ENVIRON used actual load factors provided by the operators for the selected cruise ships.

Added discussion/footnote to indicate reasons for emission differences between the ENVIRON and EIR reports.

September 2005


Responses to Specific Comments by Bluewater on Draft Final Report for the PoSF Shoreside Power Feasibility Project

Question Specific Questions/Comments

Responses

Actions

Page 1-2 Section 1.3 Caveats, Page 1-2: It seems odd that aesthetics is listed as one of the highest considerations, even before safety. Certainly this is an important but relatively minor consideration to the overall feasibility study. No doubt the architects can achieve an aesthetically acceptable design.

ENVIRON report reorganized, and discussed accordingly, that both safety and aesthetics are important in the project.

Rearranged and listed caveats in alphabetical order.

Page 1-2 Safety We want to make note of the positive finding that at other shoreside power installations, safe movement of goods and people were not negatively affected by the shoreside power equipment.

Noted in the report. None.

Page 1-3 The "worst case" conservative estimate regarding ship retrofit costs needs to be emphasized more clearly later in the report in the section on cost effectiveness. The report finds that the cost effectiveness could drop by half or more if a ship retrofits for use in other ports beyond San Francisco. In fact, we recommend that the cost effectiveness be adjusted to reflect that fact that other West Coast ports including Los Angeles, Seattle and Juneau do provide shoreside power for comparison purposes. This is particularly important for the ships calling on San Francisco that also call on Los Angeles, Seattle and Juneau.

This issue was discussed/noted in many places of the report. It would be difficult to qualitatively estimate (adjust) the cost effectiveness of shoreside power at the Port of San Francisco to account for ships berthed at other ports with shoreside power, giving that ENVIRON's scope is restricted to review and analyze port call data and vessel information for ships berthed at the Port of San Francisco. However, one can use the data presented in the ENVIRON report to develop such estimates if relevant port call and vessel data are available for other ports with shoreside power.

None.

Page 2-1 The study uses 83 as the number of port calls for 2004. However, this is incorrect if the port's calendar of cruise ship port calls for 2004 is correct at 91 port calls.

ENVIRON used the 2004 and 2005 port call data provided by the Port on Sept 2004, and noted that these data might have been revised since then.

None.

The study says it uses average berth time of 12 hours per ship. That seems inconsistent with the berthing time of the candidate ships which is more like 10 hours per ship. Please clarify.

ENVIRON report indicated that the average berth time for ALL ships berthed at the port in 2004 was 12 hours, but the average berth time for the 4 selected candidate ships was 10 hours.

None.

Page 2.3 Footnote 4 says that purchasing electricity rather than generating it with on-board engines will increase berthing costs. This may be a false assumption, as has been shown in Juneau. If cruise ships are required by state law to use cleaner fuels, using shoreside power could cost about the same or even less. This footnote should be removed from

Based on the electricity rate schedule and fuel costs available for the study, ENVIRON determined that it costs more to purchase electricity rather generating it on-board for the selected candidate ships, which are frequent callers.

Deleted footnote 4 in Section 2, but kept the discussion in the Section 8 with supporting results/data.

September 2005


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the document.

Page 2.4 The statement that gas turbine engines generally produce lower emission than conventional engines needs to be explained in more detail for clarification. Because gas turbines utilize far more fuel, the total emissions generated in a port call could be equal or more, as shown in estimates in a study done at the Port of Seattle. Due to the increase of fuel use, the release of greenhouse gases is far worse than with a diesel engine. To be fair, the report should compare the emissions of a gas turbine engine with diesel engines running on cleaner fuels and with air pollution controls and/or hooked up to shoreside power. Otherwise it gives the false impression that gas turbines are cleaner and better for the environment.

ENVIRON pointed out these issues in Section 6 of the report.

Added similar discussions in Section 2, and 4.

Page 3.1 The report says that for comparison purposes the shoreside power facility at Juneau, Alaska, was reviewed and summarized. Why did the consultant not include similar comparisons for the facility in Seattle or in Los Angeles? These are far more relevant than the Juneau facility.

In addition to the shoreside power project in Juneau, Alaska, ENVIRON discussed, used, and cited available data or information on shoreside power projects in Port of Seattle, Port of Los Angeles, and Port of Long Beach in many places of the report.

Added discussion on on-pier infrastructure cost of $1.5 million for the Port of Seattle.

Page 3.3 Table 3-1 indicates that the Regal Princess uses IFO180 because it uses that fuel in Alaska. Is there any evidence that the same fuel is used consistently by that ship in San Francisco Bay? If not, then the study should not assume so and the emissions calculations should be recalculated to reflect use of IFO380 or the appropriate fuel.

The reference of the used of IFO180 fuel in Alaska for REGAL PRINCESS was merely presenting the data provided to us by its operator. ENVIRON's emission and cost effectiveness analysis of REGAL PRINCESS was based on IFO380 fuel.

None.

Page 3.3 The shoreside power supply requirements seem to be inconsistent. The candidate ships all require loads of less than 10 MW, but the study recommends a minimum requirement of 12.5 MW. This needs to be explained better.

The transformer of the conceptual shoreside power system was specified as 12.5 MW, which was 20% higher than the anticipated average shoreside power to avoid transformer running on full capacity, as well as account for power surges or potential increases in power demand. An average 10 MW power demand, not 12.5 MW, was used by PG&E to generate the rate schedules for this study.

None.

September 2005


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Page 3.3 The study notes that cruse ships represent "2 to 3 percent of all ocean-going ship calls into San Francisco Bay." However, this is an intentionally misleading statement. Cruise ships comprise the greatest number of calls to the Port of San Francisco and represent a significant volume of air pollution at the project location. The study should be revised to show the percent of cruise ship calls to the Port of San Francisco.

Comment noted. Removed note.

Page 4.1 ENVIRON and the Port continue to overestimate the amount of time it takes to hook-up and disconnect cruise ships to and from shoreside power. This serves to intentionally underestimate the benefits of shoreside power. According to the literature, the more average time is about 30 minutes. If nothing else, the study should show both two-hour and shorter one-hour hook-up and disconnect times to provide the best and most unbiased evaluation.

ENVIRON believe that the time estimates were reasonable, giving the number of events (about 20 in each operation) that would take place for these operations (i.e. time that is required for connecting cables, synchronizing diesel generators and shoreside power, and establishing parallel operations during shoreside activation, and reverse the procedures and engine warm up during deactivation as per sequence of events listed in the report. Please note that the time estimates start the diesel generators are completed shutdown during shoreside activation, and end when the ship is completely removed from shoreside power and ready to depart.

None.

Page 4.4 This section provides additional information on the emissions profile of gas turbines, but does not discuss the complete pros and cons of these engines as previously mentioned.

See response to Page 2.4.

Page 4.5 The speed limit of 15 knots is often exceeded by cruise ships and others entering and leaving the Bay. A study by San Francisco BayKeeper found that the ships often reach 20 knots or more. This increases emissions and creates a safety and navigation threat.

Speed data used in this study were provided by San Francisco Bar Pilots as cited in the report.

None.

Page 4.9 Assuming that the fuels used by the cruise ships is 2.5 percent is not well supported. According to the literature, the average sulfur content of bunker fuels is closer to 2.7 percent. It is a small but potentially significant difference that should be considered in the calculations.

In Section 6.3, ENVIRON described the typical range for IFO fuels as 2.5% to 3.5%. IFO180 and IFO380 probably have about the same sulfur level because they only differ by a small percent of MGO or MDO mixed with residual oil. ("IFO180 or RME25 has about 6 to 7 % gas oil in it where as IFO380 or RMG35 has about 3% gas oil." http://www.bunkerworld.com/technical/tech_grades.htm). However, it has been reported that IFO fuels on the West Coast of North America have sulfur levels lower than typical range at 2%.

None.

September 2005


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(Gerry Ertl, Canadian Petroleum Product Institute, Health, Environmental, and Economic Impacts of Liquid and Atmospheric Emissions from Ships, AWMA Conference, Vancouver B.C., April, 2002) So given the likelihood that fuel sulfur tends toward lower levels when sourced from North America, ENVIRON used the low end of the typical range in fuel sulfur levels for IFO fuels.

Here it says that that Dawn Princess used .2 percent sulfur fuel. On Page 3-2 it says that the ship uses IFO180, which far exceeds that sulfur level and is usually more like 1.5 to 2.7 percent sulfur. This needs to be corrected.

CRYSTAL HARMONY used 0.2% lighter fuel, and it was incorrectly referred as DAWN PRINCESS.

Corrected.

The emissions estimates in Tables 4-9 and 4-10 need to be compared to and reconciled with the emissions estimates in the appendix of the EIR.

Addressed in the general comment. None.

The emissions estimates in Table 4-9 and 4-10 need to be totaled by ship and total emissions in order to provide the reader with a complete picture.


Page 4.11 The fact that the Dawn Princess may use 1.5 percent sulfur content fuel in Alaska does not ensure that it is used in the Port of San Francisco. This needs to be verified or the emissions calculations must be corrected to reflect use of IFO380.

ENVIRON report indicated that REGAL PRINCESS (not DAWN PRINCESS) used IFO180 in Alaska, but IFO380 data were used in the emission and cost-effectiveness analyses.

None.

Page 4.12 This section is where the study truly fails to provide the information that was sought by the CTEAC. It does not provide any basic information for the reader in an easy format. Reading these key tables do not give you any clear idea as to what the emissions reductions are for the ships in terms of totals or percentages. This entire section needs to be reformatted to reflect in one table for comparison purposes:


Total emissions per port call per ship by type of emission

Total emissions per port call per ship by type of emission when hooked up to shoreside power

September 2005


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Section 4.5 It is completely unclear why ENVIRON chose only to evaluate the emissions from a natural gas steam power plant with SCR but no CO catalyst. It should also have evaluated the emissions produced by hydro power (if any), as the electricity for the project is most likely to come from Hetch-Hetchy. In addition, ENVIRON should also compare the emissions to the total California power mix. Was this done based on the Hunter's Point Power plant, which will be shut down?

Comment noted. Used emission factors used in ARB's statewide shoreside power study.

Page 4.13 Here again, Table 4-14 fails to provide the basic information sought by CTEAC in a complete form. It does not provide any totals by ship or emission type or per port call. It also does not provide the percentage of emissions reductions. It requires the reader to perform a number of calculations on their own without being privy to the data that ENVIRON uses. We hope this is an inadvertent oversight and not an intentional effort to stymie the lay reader. This must be revised to provide the basic information that CTEAC needs.


The question these tables should answer is:

What are the emissions at the dock for each ship by type of emissions per port call?

What are the emissions reductions at the dock for each ship by type of emissions per port call if hooked up to shoreside power?

What are the percentage reductions in total and by ship?

What additional emissions are produced by shoreside power plants that provide the electricity by type of emission and by type of power: natural gas, hydro, and California power mix?

Table 4.15 Table 4-15 does not provide any additional clarity on future emissions at the dock. It is unclear why Environ used "load-weighted averages" and why transit emissions were included here. It is also unclear why Environ spent time on Figures showing the potential increase in emissions from cruise ships between 2004 and 2020 when cruise calls have nearly reached that level already and does not provide any information about how shoreside power

ENVIRON estimated the transit emissions and projected the 2020 berthing and transit emissions as per the scope of the project. These estimates can be used by the Port or the BAAQMD for emission inventory or other control measure purposes.

Added a discussion on potential percent emission reductions of 2020 berthing emissions with the use of shoreside power.

September 2005


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would reduce them. Section 8 Power demand of 12.5 MW seems

higher than needed for the ships that commonly call on San Francisco. It seems that 10 MW would provide ample energy levels based on other installations.

See response to Page 3.3. None.

The study concludes that shoreside power would provide 50 tons per year of combined emissions reductions for the candidate ships. This conclusion fails to provide the reader with the complete information needed to ascertain the significance of this number. Nor does it address the CTEAC's questions, which were, as stated above, what are the percentage reductions per ship at the dock per port call if hooked up to shoreside power by type of air emission.

Comment noted. See response to General Question #3.

Revised conclusions Section as CTEAC meeting on September 1, 05.

Another problem with this "conclusion" is that nitrogen oxide and particulate matter emissions are rarely if ever added together due to the very different nature of the compounds, the volumes and the health impacts. Doing so seems an intentional effort to cloud the results. Why are Sox emissions not mentioned?

As discussed in the report, cost effectiveness calculation for combined NOx and PM emissions is used in the Carl Moyer program. In addition, the report also provided cost effectiveness values for NOx and PM emissions, separately.

Added cost-effectiveness values for all pollutants.

The study has failed to provide the basic information needed to determine whether the emissions reductions from shoreside power are significant or not.

ENVIRON believes that the report documented the results and supporting data/information to fulfill the objective of the study.

Revised conclusions Section as CTEAC meeting on September 1, 05.

The estimated cost to retrofit ships at $500,000 to $700,000 seems too high compared to the literature. It is likely to cost far less for a new ship and for future ships as technology becomes more advanced.

ENVIRON discussed the rationale on these cost estimates, and believes that these estimates are reasonable.

None.

The cost to the cruise line for purchasing shoreside power may be far more competitive than the study estimates, particularly if the state requires ships to use marine distillate fuels in port. This should be considered in the cost effectiveness analysis.

ENVIRON discussed this issue/subject in the report, and it is not within the scope of the project to predict and/or quantify emission benefits or implication of a proposed rule.

None.

September 2005


Responses to Comments from Dock Watts on Draft Final Report for the PoSF Shoreside Power Feasibility Project

Question General Comments Responses Actions

1 Ship electric loads are broad, may not be accurate (should have 24-hour load profiles for specific ships)

ENVIRON used electric load provided by operators of the selected candidate ships, as well as port call data provided by the Port. PG&E provided rate schedules were estimated based on estimated berthing time for different power demand conditions (i.e. Peak, Part-Peak, and Off-Peak.)

None.

2 How PG&E power costs are calculated (i.e.: rate analysis, billing determinants)

ENVIRON discussed in the report data and information provided to PG&E to estimate the rate schedules for this project.

None.

3 Assumes ships only call on Port of SF (should consider multiple port calls for ship cost allocation)

This issue was discussed/noted in many places of the report. It would be difficult to qualitatively estimate (adjust) the cost effectiveness of shoreside power at the Port of San Francisco to account for ships berthed at other ports with shoreside power, giving that ENVIRON's scope is restricted to review and analyze port call data and vessel information for ships berthed at the Port of San Francisco. However, one can use the data presented in the ENVIRON report to develop such estimates if relevant port call and vessel data are available for other ports with shoreside power.

None.

4 Cost effectiveness assumes ship avoided fuel in port is HFO (trend is moving to MGO or MDO)

ENVIRON used the fuel data/information for the selected candidate ships provided by their operators.

None.

5 Potential for lower electric service cost (less than quoted 15.6 - 22 cents/kWh)

ENVIRON discussed the issue/subject in many places of the report.

None.

6 Technical errors like Princess Juneau as 16.25 MW hotel load, not considering the 6 MW electric boiler.

The 16.25 MW hotel load for Juneau, Alaska shoreside power was mentioned in the ENVIRON report but not used in any of the analyses. Our understanding is that the 16.25 MW substation is intended to serve 7 to 10 MW of hotelling electric demand, and 4 to 6 MW for steam generation.

Added/revised text in the report.

7 Technical errors like Princess Juneau was referenced to require 20-30 minutes for ships to connect/disconnect to shore power, yet the ENVIRON Report assumed 2 hours for ships to connect and disconnect when quantifying MWh/ship call.

ENVIRON believe that the time estimates were reasonable, giving the number of events (about 20 in each operation) that would take place for these operations (i.e. time that is required for connecting cables, synchronizing diesel generators and shoreside power, and establishing parallel operations during shoreside activation, and reverse the procedures and engine warm up during deactivation as per sequence of events listed in the report. Please note that the time estimates start the diesel generators are

None.

September 2005


Question General Comments Responses Actions completed shutdown during shoreside activation, and end when the ship is completely removed from shoreside power and ready to depart.

8 Technical errors like ENVIRON's cost effectiveness analysis did a 20 year Present Value of net operating cost and added capital cost. The Carl Moyer Program uses a different approach, amortizing capital cost over project life and adding net annual operating cost to amortized cost to determine $/ton cost effectiveness. This second approach is more consistent with project financed type analysis.

ENVIRON chose to use the net present value method in this study because of greater uncertainties in the future electrical energy and fuel costs than capital costs.

None.

9 Assumption of utility cost of 22 cents/kWh for all scenarios (except the four ship scenario)

PG&E generated cost schedules based on an average load demand of about 10MW, which was estimated based on actual load data for the selected ships, as well as port call and time schedule data. The report also discussed and presented energy costs used or considered in other ports that use shoreside power, as well as the implications of the energy cost on the cost effectiveness of shoreside power.

None.

10 Except for one ship, avoided fuel assumed HFO ($226/ton), MDO is $500/ton, MGO is $600/ton

See response to Q 4. None.

11 There was no consideration for ship avoided or deferred O&M cost on ship aux engines

While there might be some O&M saving on ship auxiliary engines if using shoreside power, ENVIRON believe that this saving would be insignificant giving regular O&M still are required on these engines as they are being used while away from the port.

None.

12 Data presented in the ENVIRON Report was hard to follow and could have been more clearly summarized. The ENVIRON report provided summary tables of gross emission ton/call or ton/year for each pollutant. What is needed is a summary that provides the annual emissions based on stated lb/MWh emission factors, estimated MWh/ship-call based on electric load profiles, and forecasted MWh/year based on calls per year for each ship analyzed. The data is in the ENVIRON report, just not clearly summarized (easy to do).

Addressed in comment to Bluewater. Revised report as per CTEAC meeting on September 1, 05.

13 There was limited detail in the ENVIRON report of shoreside facilities design or capital cost (referenced to Appendix D, which was not provided).

Appendix D contained supporting data for shoreside infrastructure cost estimates.

None.

September 2005


Question General Comments Responses Actions 14 Power costs were quoted as 15.6 to 22

cents/kWh, there was no analysis of PG&E rates, billing determinants, peak demand, and load profile. The ENVIRON report had very little to say on other utility service options, rates, and rate mechanics, demand charge and energy charge interplay other than a general reference to potential PG&E interruptible tariff to reduce cost on a cent/kWh basis. There was reference to LADWP's 8.5 cent/kWh shore power cost at the Port of LA. Rough estimate of breakeven cost for PG&E service to be equivalent to MDO fuel is 12.1 cents/kWh.

See response to Q 9. None.

September 2005


Responses to Comments by PG&E on Draft Final Report for the PoSF Shoreside Power Feasibility Project

Commenter Report Section

Statement

Comments

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PG&E 2.3 & 4.2 References to gas turbines used in this application as having significantly lower emissions than diesels is confusing since none of the ships being considered are so equipped.

References to gas turbines should be deleted.

As noted in the ENVIRON report, there are some cruise ships using gas turbines as their propulsion and auxiliary engines.

None.

PG&E 3.1 Using Juneau as an example of a shore power project for cruise ships presents an unduly negative picture of this technology and not representative of the situation inSan Francisco.

Replace this example with the Seattle example Shore Power example.

In addition to the shoreside power project in Juneau, Alaska, ENVIRON discussed, used, and cited available data or information on shoreside power projects in Port of Seattle, Port of Los Angeles, and Port of Long Beach in many places of the report.

Added discussion on on-pier infrastructure cost of $1.5 million for the Port of Seattle.

PG&E 3.3, 3.4, 5.7 & 5.8

The power demand for this project is mislabeled as Megawatts (MW) and subsequently used elsewhere in the report as the demand for the project.

The electrical demand as defined in this report is 10 Megawatts (MW). Electrical demand is measured in MW and energy measured in MW Hours (MWH). PG&E’s rate schedules charge for demand and energy in these units. MVA is generally only used for the purposes of designing electrical equipment. MVA is calculated as follows, 10 MW x Power Factor of 0.8 = 12.5 MVA. This error causes a 20% over estimation in total energy cost. I would recommend that references to MVA and power factor be eliminated because of the confusion they seem to be causing.

The transformer of the conceptual shoreside power system was specified as 12.5 MW, which was 20% higher than the anticipated average shoreside power to avoid transformer running on full capacity, as well as account for power surges or potential increases in power demand. An average 10 MW power demand, not 12.5 MW, was used by PG&E to generate the rate schedules for this study.

Removed reference of MVA.

September 2005


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PG&E 4.1 Time to connection to Shore Power- the study presents data as a finite point value of 2 hours.

Other studies have estimated this time at closer to 30 minutes. A range of values might be more appropriate.

ENVIRON believe that the time estimates were reasonable, giving the number of events (about 20 in each operation) that would take place for these operations (i.e. time that is required for connecting cables, synchronizing diesel generators and shoreside power, and establishing parallel operations during shoreside activation, and reverse the procedures and engine warm up during deactivation as per sequence of events listed in the report. Please note that the time estimates start the diesel generators are completed shutdown during shoreside activation, and end when the ship is completely removed from shoreside power and ready to depart.

None

PG&E 4.5 In attempting to quantify the emission benefit of shore power and hence the cost effectiveness of this option ENVIRON nets out the emission reduction from shore power less an assumed increase in emissions from utility generation. A gas turbine is used as a proxy for utility emissions.

Electric utilities get their power from a number of resources. In 2004 more than 51% of PG&E’s retail electric sales were generated from resources that had no air emissions at all, principally hydro and nuclear. While this mix of resources can vary significantly from year to year, a gas turbine would be a last resort source of energy. The Suggested Values in

Comment noted. Used emission factors used in ARB's statewide shoreside power project.

September 2005


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the table below are drawn from two sources CARB and PG&E’s 2004 Corporate Responsibility Report.

Utility Emission Factors (lbs/MW-hr)

Pollutant ENVIRONSuggested

Value SourceNOx 0.11 0.00095 PG&ECO 0.96 0.257 CARBPM 10 0.087 0.027 CARBSO2 0.0069 0.00001 PG&EVOC 0.063 0.035 CARB

Commenter Report Section

Statement

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PG&E 5.9 & 8 The utility power cost estimate presents the average cost of energy under the E-20P rate schedule as $0.156/KWH and the E-BID curtailment savings of $0.019/KWH separately but never adds the two together.

The totals cost of energy for the 4 ship example should be between $0.141 and $0.137/KWH.

$0.141/kW-hr was used in the analysis.

None.

PG&E 6.2 Table 6-2 is identified as “a range of feasible alternatives.” and includes SCR’s, IWS’s, DOC’s and DPF’s. Later in the section SCR’s, IWS’s, DOC’s and DPF’s are said to not be feasible.

This inconsistency needs to be resolved.

Comment noted. Revised to "a range of potential feasible alternatives."

PG&E 6.3 Fuel pricing quoted in this section is from March 2005.

These fuel prices should be updated and include all delivery costs to the ship.

Fuel prices used in the report were spot prices when the time the analysis was performed (August 05).

Added a footnote.

PG&E 6.5 Table 6-4 appears to include only Capital and Operating costs and does not include the additional cost of fuel in the case of MGO or in the case of the MGO/Emulsion the cost of the emulsifier.

Include cost of fuel in this computation.

Estimates in Table 6-4 include both capital and operating costs, including incremental fuel costs.

None.

September 2005


Responses to Comments by PRINCESS on Draft Final Report for the PoSF Shoreside Power Feasibility Project

Statements/Comments Responses Actions 1. Celebrity may have a gas-turbine ship in San Francisco. Mike Nerney could verify this.

Noted in response to PG&E None

2. Princess has several ships with gas turbine engines (Diamond, Sapphire, Island, and Coral). All are equipped to connect to shorepower. Some of these ships may be scheduled into San Francisco in the future.

Noted in response to PG&E None

3. Agree that Seattle should be a better comparison than Juneau for shoreside capital cost for the transformer and connection systems. Total cost in Seattle is estimated at $1.5 million.

Noted in response to PG&E and Bluewater

None

September 2005


Responses to Comments by SFPUC on Draft Final Report for the PoSF Shoreside Power Feasibility Project

Statements/Comments Responses Actions While the construction costs are preliminary and represent ranges of expected costs for the associated routes, it appears that ENVIRON's analysis excludes certain costs that PG&E would otherwise require the applicant to pay for electric service connections. These costs include: an ITCC tax of 34%, a Special Facilities Charge, and a Cost of Ownership Charge.

The ITCC tax, special facilities charge and cost of ownership charge were not estimated in the study, and might not be feasible to do so without performing an Engineering Feasibility Study, which is not the scope of the project. However, ENVIRON discussed in Section 6 of the report that cost estimates for the shoreside infrastructure costs do not take into account any costs of facilities needed to provide service to the terminal itself, and that the actual cost of facilities necessary to provide shoreside power to the ships would be the combined cost electrical service facilities required to serve the terminal and shoreside power less the cost of the costs of facilities to serve the terminal only.

None

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