3. Terms of Settlements

3.1. May 13, 2005 Settlement

The 16 parties joining in the May 13, 2005 settlement include all the active parties. The May 13, 2005 Settlement resolves marginal cost, revenue allocation and some rate design issues.

In summary, the major points of the May 13, 2005 Settlement provide that:

a. Marginal Cost: Settling Parties agree not to address electric marginal costs in this proceeding. Rather, Settling Parties generally agree that the residential customer class is bearing less than its full cost of service while most non-residential customer classes are bearing more than their cost of service. To better align rates with costs, Settling Parties agree on revenue allocation, and that no further assessment of marginal cost is needed here.

b. Revenue Allocation: Settling Parties agree to specific revenue allocations, or allocation methodologies.

1. Five revenue changes before January 1, 2006: Two revenue increases, and one decrease, are allocated to all classes on a system average percentage basis consistent with the allocation guidance set forth in the Rate Design Settlement Agreement (RDSA). (D.04-02-062, Paragraph 10 of the RDSA.) This essentially changes the revenues for each customer class by the same percentage on a function by function basis. Two decreases will be allocated entirely to the non-residential classes consistent with the RDSA method on a component by component basis.

2. A.04-06-024 Rate Changes on January 1, 2006: Electric revenues are reallocated on a revenue neutral basis using agreed upon sales forecasts, generally resulting in a slight increase for residential customers, and decreases for other customers. Also, $2.97 million is moved from generation to the nuclear decommissioning component of rates, slightly reducing revenue collected from bundled customers and increasing the revenue from Direct Access (DA) customers, consistent with the Phase 1 decision. (D.04-05-055, Attachment A, page 12.)

The table below shows the average electric rates for each customer class as of March 1, 2005. It also shows the approximate average electric rates that would be expected January 1, 2006 by application of the RDSA (without the changes agreed to in the May 13 Settlement), and those expected to result from the May 13, 2005 Settlement. These rates are for the 5 revenue requirement changes before January 1, 2006 and the revenue neutral allocation January 1, 2006. Finally, it shows the percent changes.

TABLE 1

CURRENT, RDSA AND SETTLEMENT

AVERAGE RATES

CLASS	CURENT RATE (March 1, 2005) (cents per kWh) A	RDSA RATE (January 1, 2006) [1] (cents per kWh) b	SETTLEMENT RATE (January 1, 2006) (cents per kWh) c	PERCENT CHANGE (RDSA from current) d = b/a	PERCENT CHANGE (Settlement from RDSA) e = c/b	PERCENT CHANGE (Settlement from Current) f = c/a
BUNDLED
Residential	12.802	12.500	13.067	-2.4%	4.5%	2.1%
Small L&P	15.042	14.588	13.858	-3.0%	-5.0%	-7.9%
Med L&P	14.277	13.563	12.575	-5.0%	-7.3%	-11.9%
E-19	12.855	12.190	11.342	-5.2%	-7.0%	-11.8%
Street Lights	15.129	14.988	14.399	-0.9%	-3.9%	-4.8%
Standby	13.636	13.086	12.402	-4.0%	-5.2%	-9.0%
Agricultural	11.917	11.676	11.275	-2.0%	-3.4%	-5.4%
E-20	10.652	9.995	9.279	-6.2%	-7.2%	-12.9%
Total	12.990	12.512	12.300	-3.7%	-1.7%	-5.3%
DIRECT ACCESS
Residential	8.418	8.480	8.484	0.7%	0.1%	0.8%
Small L&P	8.351	8.530	8.534	2.1%	0.0%	2.2%
Med L&P	6.535	6.673	6.664	2.1%	-0.1%	2.0%
E-19	6.068	6.191	6.190	2.0%	0.0%	2.0%
Agriculture	6.235	6.362	6.365	2.0%	0.1%	2.1%
E-20	3.924	3.957	3.984	0.8%	0.7%	1.5%
Total	4.833	4.901	4.915	1.4%	0.3%	1.7%

[1] Absent the revenue allocation in the May 13 Settlement, Settling Parties assume all revenue changes would be allocated based on the method in the RDSA, and result in the rates estimated herein.

L&P is Light and Power.

3.

4. Other Changes on January 1, 2006: Revenue requirement changes for 11 specifically identified proceedings are categorized into three functional groups (generation-related, non-generation-related, fixed transition amount (FTA)-related), and the allocation treatment is specified. The ratemaking applies only to these 11 proceedings. Settling Parties make no assumptions about the direction or size of these 11 revenue requirement changes. In general, revenue increases will be allocated to all groups (with increases to residential classes potentially offset by some FTA-related decreases). All other decreases will be allocated only to non-residential groups. Settling Parties also agree to an approach should the revenue changes be delayed until after January 1, 2006.

5. Other Revenue Requirement Changes: Settling Parties agree that allocation of revenue changes other than those explicitly listed, and specifically for those after January 1, 2006 and before the effective date of the rate design decision in PG&E's next GRC, will be governed by the RDSA, not the specific revenue allocations stated in this May 13, 2005 Settlement, or as otherwise ordered by the Commission.

6. Other Revenue Allocation Issues: Any remaining allocation issues are deferred to Phase 2 of PG&E's 2007 GRC.

c. Rate Design

1. Direct Access Cost Responsibility Surcharge (DA CRS): Settling Parties agree that non-core bundled customers have funded more than their share of the DA CRS undercollection, and agree to certain rate adjustments until the Commission looks at DA CRS funding in R.02-01-011 or as the Commission may otherwise direct.

2. Nonfirm Program Incentives: The incentive for nonfirm service shall be retained at the level now in effect until the Commission determines otherwise in PG&E's next GRC or elsewhere (e.g., A.05-01-016, et al. Critical Peak Pricing proceeding).

3. Phase 2 of Baseline Rulemaking: Shortfalls from programs adopted in Phase 2 of the Baseline Rulemaking (D.04-02-057) will be recovered from the residential class by function based on the RDSA method.

4. Residential Generation Revenue Memorandum Account (RGRMA): Tier 3 and 4 rate levels resulting from Resolution E-3906 were reasonable and require no adjustment. The RGRMA can be eliminated.

5. Electric Master Meter Discount: The master-meter discount for Schedule ET- Mobilehome Park Service is increased from $0.343 to $0.379 per space per day until the next GRC Phase 2 proceeding. The master-meter discount for Schedule ES-Multifamily Service remains the same at $0.10579 per unit per day.

6. Streetlight Non-Energy Charges: Changes will be effective March 1, 2006 (rather than January 1, 2006), various elements are set (e.g., hookup costs, non-conforming load requirement conditions, meter charges, photocontrol standards, revenue requirement for non-energy charges), and tables adopted for revenue requirement, allocation and rates. Exhibit 47 contains the street light class tariffs related to the May 13, 2005 Settlement to which parties agree.

3.2. Supplemental Residential Settlement

The 3 parties joining in the Supplemental Residential Settlement are all the active parties on residential issues. Rates are to be designed as set forth in the supplemental settlement, and illustrative rates are the starting point for determining rate changes on January 1, 2006 necessary to collect the adopted revenue requirement. In summary, the major points of the Supplemental Residential Settlement provide that:

a. California Alternate Rates for Energy (CARE): CARE rates will remain unchanged. The current calculation of CARE rates shall be retained.

b. Baseline: Target baseline quantities in PG&E exhibits are to be adopted. Applicant shall file advice letters in 2006 to phase-in the new quantities on April 1, 2006 (gas) and May 1, 2006 (electric), subject to existing 5 percent single-family and 10 percent multifamily baseline quantity phase-in bill increase limitations for electric service.

c. Tier 3, 4 and 5 Surcharges: Prior to a decision in applicant's 2007 GRC Phase 2, rates for usage in excess of 130 percent of baseline for non-CARE customers shall be determined by setting the Tier 3, 4 and 5 surcharges the same on all applicable non-CARE residential rate schedules.

d. Medical Baseline: Effective May 1, 2006, medical baseline rates remain unchanged for usage below 130 percent of baseline, but a new Tier 3 rate equal to the non-CARE Tier 3 rate shall apply to all usage in excess of 130 percent of baseline. Medical baseline customers will be eligible to apply for the Family Electric Rate Assistance (FERA) program.

e. Time of Use (TOU): Existing TOU rates are closed, and new revenue-neutral TOU rates are opened, on May 1, 2006.

f. Installation Charges: Certain installation charges are eliminated May 1, 2006, and two existing TOU meter charges shall continue at their current level.

g. Rate Differential by Tier: Total rates shall be designed such that the rate differential by tier shall be made up of both generation and distribution within each tier in the same proportion as total distribution to generation revenues allocated to schedule.

h. Employee Discount: The current employee discount shall apply the 25 percent discount to the full Tier 1 rate, plus 25 percent of the full Tier 2 rate for all usage over baseline.

i. Illustrative Rates: Rates are shown which collect the revenue allocated in Table 2 of the May 13, 2005 Settlement. Adopted revenue requirements shall be applied to these initial rates.

3.3. Supplemental Small Light and Power Settlement

The 4 parties joining in the Supplemental Small Light and Power Settlement are all the active parties on these issues. Rates are to be designed as set forth in the supplemental settlement, and illustrative rates are the starting point for determining rate changes on January 1, 2006 necessary to collect the adopted revenue requirement. In summary, the major points of the Supplemental Small Light and Power Settlement provide that:

a. Customer Charges: Customer charges for Schedules A-1 and A-6 are increased to $8.10 and $12.00 per month for single phase and poly phase service, respectively. Customer charges for Schedules A-15 and TC-1 remain at current levels. The facilities charge for Schedule A-15 shall be increased to $15.00 per month.

b. TOU Charges: Effective May 1, 2006, Schedule A-6 TOU processing and installation charges are eliminated, and ongoing meter charges remain at current levels.

c. Commercial CARE: The calculation of commercial CARE bills shall remain unchanged and rely on a 20 percent discount based on the methodology specified in Schedule E-CARE.

d. Energy Rates for Schedule A-15: The energy rates for the unbundled public purpose program, distribution and generation rate components of Schedule A-15 will be set equal to those calculated for Schedule A-1.

e. Schedule E-36: Effective May 1, 2006, Schedule E-36 shall be discontinued and existing customers transferred to Schedule A-1 or another applicable schedule.

f. Illustrative Rates: Rates are shown which collect the revenue allocated in Table 2 of the May 13, 2005 Settlement. Adopted revenue requirements shall be applied to these initial rates.

3.4. Supplemental Light and Power Settlement

The 9 parties joining in the Supplemental Light and Power Settlement are all the active parties on these issues. Rates are to be designed as set forth in the supplemental settlement, and illustrative rates are the starting point for determining rate changes on January 1, 2006 necessary to collect the adopted revenue requirement. In summary, the major points of the Supplemental Light and Power Settlement provide that:

a. Methods: Basic rate designs will be updated using methods proposed by PG&E in Exhibit 11, with limited exceptions to mitigate changes from existing relationships under Schedules E-19 and E-20.

b. 15-Minute Demand Charge Interval: Effective May 1, 2006, demand charge intervals are changed from 30 minutes to 15 minutes for service under Schedules E-19, E-20, A-10 (over 400 kW demand) and E-19V (over 400 kW demand).

c. Customer Charges: PG&E's proposed customer charges are adopted.

d. Rate Limiters: Summer season on-peak rate limiters for Schedules E-19 and E-20 are eliminated. Summer season average rate limiters continue to be applicable for customers on Schedules E-19 and E-20 taking service at distribution voltages.

e. Optimal Billing Program: Effective May 1, 2006, the Optimal Billing Program is eliminated. (This program allowed certain food processing customers on Schedules E-19 and E-20 to re-designate certain meter read dates at the beginning and end of their peak processing seasons.)

f. Discontinue Schedule E-25: Effective May 1, 2006, Schedule E-25 is eliminated. (This is a short-peak-period TOU rate option for less than 10 qualifying water agency customers otherwise eligible for Schedules E-19 or E-20.)

g. Power Factor Adjustments: Effective May 1, 2006, power factor adjustment rates are converted on a revenue neutral basis from a percentage of billed revenues basis to a per kilowatt-hour (kWh) basis.

h. TOU Meter Charges: Effective May 1, 2006, TOU installation and processing charges are eliminated for customers with demand less than 500 kW electing to take voluntary TOU service under Schedule E-19.

i. Energy Efficiency Clause on Schedule E-20: The Energy Efficiency Adjustment clause is eliminated from Schedule E-20 (established over 15 years ago to maintain eligibility for service under Schedule E-20 for a limited number of customers who would otherwise be served on Schedule E-19).

j. Updated Standby Service Rates: PG&E's proposed methods for setting standby rates are reasonable. Further consideration is deferred to Phase 2 of PG&E's 2007 GRC of the issue regarding distribution-voltage standby rates that might fully allocate distribution capacity costs to Schedule S on the same basis as if no customer generation were installed.

k. New Physical Assurance Contract: Effective May 1, 2006, PG&E's proposed standard form contract for Physical Assurance is adopted with respect to distributed generation customers taking service under Schedule S.

l. Eliminate Non-Firm Rate Option Under Schedule S: The new Physical Assurance Agreement may be used as a substitute for establishing separate non-firm service rates for standby customers.²

m. Ratchet for Standby Contract Demand: Effective May 1, 2006, the standard ratchet period is reduced from 36 months to 12 months for standby service reservation capacity elected under Schedule S.

n. Standard Non-Firm Service Rates: PG&E will restate the existing non-firm program terms and conditions and corresponding rate credits in the form of a separate, supplementary rate schedule. The supplementary schedule will then apply as a rider to otherwise applicable charges under Schedules E-19 or E-20.

o. Non-Firm Rate Eligibility: Non -firm tariff eligibility is restored for a small number of customers who previously took non-firm service but who lost their eligibility due to a change in corporate ownership.

p. Schedule E-BIP: Schedule E-BIP is modified to include an Underfrequency Relay (UFR) service option comparable to that under PG&E's standard non-firm tariffs. Participants electing the UFR program agree to make their load available for complete and automatic interruption in the event of certain system disturbances and receive an additional incentive of $8.00 per kW per year.

q. Account Aggregation Proposals Deferred: Further consideration of account aggregation proposals for agricultural and water agency pumping load is deferred to Phase 2 of PG&E's 2007 GRC.

r. Illustrative Rates: Rates are shown which collect the revenue allocated in Table 2 of the May 13, 2005 Settlement. Adopted revenue requirements shall be applied to these initial rates.

3.5. Supplemental Agricultural Settlement

The 4 parties in the Supplemental Agricultural Settlement are all the active parties on these issues. Rates are to be designed as set forth in the supplement settlement, and illustrative rates are the starting point for determining rate changes on January 1, 2006 necessary to collect the adopted revenue requirement. In summary, the major points of the Supplemental Agricultural Settlement provide that:

a. Agricultural Applicability: The agricultural applicability definition (i.e., agricultural class definition) will be addressed separately, and parties will seek a separate decision by January 2006. Parties agree the definition does not affect the development or implementation of rates January 1, 2006.

b. Rate Consolidation: Current agricultural rate schedules shall be retained and PG&E's proposed rate consolidation will be dropped. Effective May 1, 2006, Schedule AG-7 shall be eliminated and customers given rate analyses to assist in selecting another rate schedule.

c. Ratcheted Demand Charges: Ratcheted demand charges shall be discontinued (including both the demand charge rate limiter and drought relief option tied to ratcheted demand charges). Balance of contract and minimum demand provisions shall be eliminated.

d. Schedules AG-4C and AG-5C: Shall be redesigned to replace the current off-peak ratcheted maximum demand charges with a standard maximum demand charge. By May 1, 2006, voltage discounts shall be made available.

e. TOU Meter Charges: Effective May 1, 2006, TOU meter installation and processing charges are eliminated. The two current daily TOU meter charges are retained, with the lower daily charge applicable only to customers who paid the installation charge prior to its elimination.

f. DAP and GAP Options: Effective May 1, 2006, the current Diesel Alternative Power (DAP) and Natural Gas Alternative Power (GAP) options are discontinued.

g. Account Aggregation: Further consideration of agricultural and water agency pumping load account aggregation proposals is deferred to Phase 2 of PG&E's 2007 GRC. PG&E will provide staff and other resources for a study mutually agreed to between PG&E, Agricultural Energy Consumers Association (AECA), California Farm Bureau Federation (CFBF) and East Bay Municipal Utility District (EBMUD).

h. Data: PG&E will make specified data available to AECA and CFBF at the time PG&E files Phase 2 of its 2007 GRC.

i. Changes: Except as specified herein, revenue allocation and rate design shall use equal percentage change methods established in the RDSA. Rates for oil pumping Schedule E-37 shall be set equal to the rates in Schedule AG-5B.

j. Illustrative Rates: Rates are shown which collect the revenue allocated in Table 2 of the May 13, 2005 Settlement. Adopted revenue requirements shall be applied to these initial rates.

3.6. Supplemental Energy Recovery Bond Settlement

The 2 parties to the Supplemental Energy Recovery Bond Settlement are the active parties on this issue. In summary, Settling Parties agree that while the cap for departing load customer should include the ERB, in the unlikely event that ERB cannot be collected under the cap, rates will be adjusted to ensure that the ERB is fully collected from the responsible customers.

More specifically, Settling Parties agree that, to the extent the Commission determines that the $0.027 per kWh cap on the Cost Responsibility Surcharge (CRS) is appropriate for any Departing Load (DL) customers, and if the full amount of the energy recovery bond charges are recoverable under the cap, the capped amount shall include recovery of the following components in the following order: (1) Department of Water Resources (DWR) Bond Charge, (2) Energy Cost Recovery Amount (the amount of ERB charges specified in Ordering Paragraph 65 of D.04-11-015), (3) Ongoing Competitive Transition Charges (CTC), and (4) DWR Power Charges. In the remote event that the ERB charges cannot be recovered from all responsible customers under the $0.027 per kWh CRS cap, rates will be adjusted such that the ERB charge is fully recovered from all responsible customers on a timely basis without deferral. Any shortfall that results will be attributed only to the CRS component that is not fully recovered. The shortfalls resulting from the capping will then be recovered only from those DL customers who are required to pay the particular CRS component that was not fully recovered due to the cap. As a result, customers not required to pay ERB charges will not be required to pay ERB shortfalls. Only non-exempt capped customers are responsible for their respective shortfalls.

² Settling Parties state that no customer would be affected by eliminating the existing provisions for non-firm standby service because no Schedule S customer has ever elected this service option.