PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

I.D. #7466

ENERGY DIVISION RESOLUTION E-4160

April 10, 2008

RESOLUTION

Resolution E-4160. This Resolution directs Bear Valley Electric Services (BVES), Pacific Gas & Electric Company (PG&E), San Diego Gas & Electric (SDGE), and Southern California Edison Company (SCE) to alter collection of a portion of the public goods charge that funds investments in renewable energy; sets a limitation on total costs expended above the Market Price Referent (MPR) for BVES, PG&E, SDGE, and SCE renewable power purchase agreements (PPAs); and formally adopts eligibility criteria and guidelines for approving requests for Above-MPR Funds (AMFs) for eligible renewable energy contracts procured through competitive solicitations.

This Resolution is made on the Commission's own motion.

__________________________________________________________

Summary

Senate Bill 1036 modifies the amounts BVES, PG&E, SDGE, and SCE are to collect from ratepayers for renewable energy programs and requires the California Public Utilities Commission (Commission) to develop new rules for the Renewables Portfolio Standard Program

Senate Bill (SB) 1036¹, effective January 1, 2008, modifies elements of the Renewables Portfolio Standard (RPS) program. SB 1036 eliminates the responsibility of the California Energy Commission (CEC) to award supplemental energy payments (SEPs) to eligible renewable energy resources to cover above-market costs of renewable energy contracts. SB 1036 also requires the CEC to transfer all unencumbered funds in the New Renewable Resources Account² back to BVES, PG&E, SDGE, and SCE³, and their respective ratepayers. The Commission must ensure that the funds received from the CEC are allocated by the electrical corporations in "a manner that maximizes the economic benefit to all customer classes that funded the New Renewable Resources Account".⁴ SB 1036 further directs PG&E, SDGE, and SCE, the three large investor owned utilities, (IOUs) to alter the amounts of funds collected annually from customers for the public goods charge (PGC) for renewable energy. In addition, SB 1036 directs the Commission to establish, for each electrical corporation, a limitation on the total costs expended above the market price referent (MPR) for the procurement of eligible renewable energy resources procured to satisfy RPS goals. As a result, rather than renewable generators seeking SEPs from the CEC for the above-market costs of RPS contracts negotiated through competitive solicitations, the IOUs are now required to seek above-market cost recovery for eligible RPS contracts procured via a competitive solicitation.

This Resolution implements SB 1036 in the following ways:

1) Directs PG&E, SDGE, and SCE to adjust their respective Public Purpose Program (PPP) rate components collecting PGC as directed by Public Utilities (Pub. Util.) Code § 399.8 and amended by SB 1036;

2) Directs PG&E, SDGE, and SCE to amortize funds transferred from the New Renewable Resources Account, administered by the CEC, in their PPP rate component;

3) Directs BVES to establish an account to record unencumbered renewable funds transferred from the CEC back to BVES. Funds recorded in this account shall accrue interest at the three month commercial paper rate, and shall be amortized in rates and returned to customers beginning no later than April 1, 2009;

4) Establishes the cost limitation for above-MPR costs that each IOU can expend on the procurement of eligible renewable energy resources solicited through competitive solicitations. The funds that may be applied towards the cost limitation will be called the Above-MPR Funds (AMFs);

5) Outlines methodology for an AMF Calculator for the calculation of AMFs requests and the tracking of approved AMFs requests; and

6) Sets forth eligibility criteria and reasonableness standards for renewable power purchase agreements (PPAs) with above-MPR costs that may be applied toward the cost limitation. The standards are to ensure that the limited amount of AMFs is used efficiently and in a manner that maximizes ratepayer benefit.

2. Background

2.1 SB 1078 Established the RPS Program and Set Forth Mechanisms for Funding the Above-Market Costs⁵ of RPS Contracts

The California RPS Program was established by Senate Bill (SB) 1078⁶ and codified in California Pub. Util. Code § 399.11, et seq. The statute required that each retail seller of electricity increase its total procurement of eligible renewable energy resources by at least one percent of annual retail sales per year so that 20 percent of its retail sales are supplied by eligible renewable energy resources by 2017. In 2006, SB 107⁷ accelerated the RPS target to reach 20 percent renewable procurement by 2010.

Pursuant to SB 1078 and SB 107, the CEC was authorized to "allocate and award supplemental energy payments" (SEPs) to cover above-market costs of long-term RPS-eligible contracts executed through a competitive solicitation. In order to calculate the above-market costs of renewable energy contracts, Pub. Util. Code § 399.15(c) requires the Commission to adopt a Market Price Referent (MPR) methodology to estimate the long-term market price of electricity. The MPR represents the presumptive cost of electricity from a non-renewable energy source, which this Commission holds to be a natural gas-fired baseload or peaker plant.⁸ The MPR establishes a benchmark at or below which approved RPS bid contracts will be considered per se reasonable, and can be recovered in rates. Prior to SB 1036, long-term contracts negotiated through a competitive solicitation, with contract costs above the MPR, were eligible to receive SEPs. The SEP award was to be calculated as the net present value of the above-MPR costs, accounting for the IOU's TOD profile, over the term of the contract. The statute required that developers seeking above-market costs apply to the CEC for SEPs, and the SEPs were to be disbursed from the New Renewable Resource Account (NRRA).

SB 90⁹ established the NRRA within the Renewable Resource Trust Fund, administered by the CEC, to foster new in-state renewable electricity generation facilities. The NRRA was funded via a portion of the Public Goods Charge (PGC). ¹⁰ The PGC is a component of the IOUs' Public Purpose Program Revenue Requirements, which is collected from customers in rates authorized by the Commission and described below in more detail.

2.2 The Commission Implemented Public Goods Charge Collection Methodologies

Assembly Bill (AB) 1890¹¹ codified Pub. Util. Code § 381 and authorized the electrical corporations to collect the PGC in rates for Public Purpose Programs for the period from 1998 to March 2002. The PGC is a nonbypassable rate component intended to fund in part energy efficiency (EE), renewable resource energy technology (Renewables), and public interest research and development (RDD). A portion of the collected funds is remitted to the CEC to fund renewable energy programs and public interest research and development activities. Pub. Util. Code § 381(g) stated that the Commission's authority to collect funds pursuant to that section expired on March 31, 2002. AB 995¹² reauthorized the funding through January 1, 2012 by adding Pub. Util. Code § 399.8.

Prior to the adoption of SB 1036, Pub. Util. Code § 399.8 directed the Commission to order the IOUs to continue to collect funds for the EE, Renewables, and RDD programs from customers through a nonbypassable PGC rate component. § 399.8(d)(1) specified that these utilities were to collect, in aggregate, the following amounts for each year starting January 1, 2002 and ending January 1, 2012:

Table 1

Required Yearly Program Funding Starting 2002¹³

($ million)

The statute did not specify how much of this annual total was to be allocated among the three largest IOUs¹⁴, however. Thus, the Commission issued Resolution E-3792 on December 17, 2002. This Resolution set forth the IOUs' funding allocations for the yearly programs from January 1, 2002 through January 1, 2012 to fund investment in the three types of Public Purpose Programs (Table 2).

Table 2

Allocation to PPP Programs by Utility¹⁵

2002-2011

($ million)

Neither § 399.8 nor Resolution E-3792 required BVES to collect a PGC for EE, Renewables, or RDD programs. BVES, however, filed Application 97-08-064 proposing an $112,000 rate increase to fund new Public Purpose Programs associated with renewable resource technologies and research and development. Commission Decision 97-12-093 approved the application, and as a result, BVES filed Advice Letter 175-E, requesting approval of its tariffs reflecting the $112,000 rate increase.¹⁶ The collected funds were remitted to the CEC, who administered the NRRA pursuant to Pub. Util. Code § 381. In 2004, the Commission issued Resolution E-3856¹⁷ authorizing BVES to continue collection of funds for public purpose programs related to research and development and renewable resource technologies.

2.3 SB 1036 Amends Pub. Util. Code § 399.8(d), Pub. Util. Code § 399.15(d), Public Resource Code 25751(b), and Public Resource Code 25743

The mechanism for awarding above-market costs to eligible renewable energy contracts negotiated through a competitive solicitation was modified on October 14, 2007 when Governor Schwarzenegger signed SB 1036. The bill eliminates the CEC's authorization, set forth in SB 1078 and SB 107, to "allocate and award supplemental energy payments" to cover above-market costs of RPS contracts. Further, SB 1036 added Pub. Res. Code § 25743, requiring the CEC to transfer the unencumbered funds in the New Renewable Resources Account back to the IOUs by March 1, 2008. SB 1036 also amends Pub. Util. Code § 399.8(d) to eliminate future collection of SEP money from IOU customers by reducing the amount of money IOUs are to collect for the Renewables programs portion of the PGC.¹⁸

Further, SB 1036 requires the Commission to establish a limitation on the total costs expended above the market prices for each IOU; the limitation must be equal to the amount of funds currently accrued in the New Renewable Resources Account, plus the portion of PGC funds that would have been collected for SEPs through January 1, 2012. SB 1036 sets forth eligibility criteria (e.g. only contracts negotiated through a competitive solicitation) for the RPS contracts that may be counted towards the cost limitation. As a result, rather than renewable generators seeking SEPs from the CEC for the above-market costs of RPS contracts negotiated through competitive solicitations, the IOUs are now required to seek above-market cost recovery for eligible RPS contracts procured via a competitive solicitation. These costs will then be applied towards the IOU's cost limitation.

3. Discussion

This Resolution implements SB 1036 in the following ways:

1) Directs the IOUs to adjust their respective PPP rate components collecting the PGC;

2) Directs the IOUs to amortize funds transferred from the New Renewable Resources Account in their Public Purpose Program rate component;

3) Directs BVES to establish an account to record unencumbered renewable funds transferred from the CEC back to BVES.

4) Establishes the total cost limitation for above-MPR costs each utility can expend on the procurement of eligible renewable energy resources;

5) Outlines methodology for an AMF Calculator for the calculation of AMFs requests and the tracking of approved AMFs requests;

6) Sets forth eligibility criteria for power purchase agreement costs that may be applied to the cost limitation;

7) Sets forth reasonableness standards for reviewing above-MPR contract costs; and

8) Sets forth administration rules for the AMFs.

3.1. Certain Actions are Required by BVES, PG&E, SDGE, and SCE Pursuant to Amended Pub. Util. Code § 399.8(d) and Public Resource Code § 25743

3.1.1. IOUs must alter PGC collection

Resolution E-3792, pursuant to § 399.8(d), directed each IOU to collect monies from January 1, 2002 through January 1, 2012 to fund investment in energy efficiency, renewable energy, and research demonstration and development projects. SB 1036 amends § 399.8(d); specifically, it alters the amount of money IOUs are to collect for renewable energy programs. We direct PG&E, SDGE, and SCE to file advice letters, within ten days of the effective date of this Resolution, to alter collection of a portion of the PGC as directed by § 399.8(d), as amended by SB 1036 which states in part:

The commission shall order San Diego Gas and Electric Company, Southern California Edison Company, and Pacific Gas & Electric Company to collect these funds commencing on January 1, 2002, as follows:

Two hundred twenty-eight million dollars ($228,000,000) per year in total for energy efficiency and conservation activities, sixty-five million five hundred thousand dollars ($65,500,000) in total per year for renewable energy, and sixty-two million five hundred thousand dollars ($62,500,000 in total per year for research, development and demonstration.

The effective date of the funding adjustment is January 1, 2008. Allocation by IOU of the $65,500,000 for the Renewables Programs will remain consistent with the allocation set forth in Resolution E-3792, but will reflect the amended total amount to be collected (Table 3). The amended total amount is a 51.5 percent reduction in Renewables program funding, which is the portion of the Renewables program funding that was allocated towards SEPs before SB 1036.

Table 3

Allocation to Renewables Program by Utility

2002-2011

($ million)

Allocations to energy efficiency and research, development and demonstration programs by IOU have not been modified (Table 4). Thus, collection allocations will remain the same as set forth in Resolution E-3792. Additionally, monies for the RDD program shall continue to be forwarded to the CEC, along with interest earned on collected funds, consistent with the treatment of these funds in § 381. EE programs will continue to be administered by this Commission, pursuant to Pub. Util. Code § 399.4(a)(1).

Table 4

Allocation to Programs by Utility¹⁹

2002-2011

($ million)

As stated in Pub. Util. Code § 399.8(d)(2), amounts collected for all programs shall be adjusted annually at a rate equal to the lesser of the annual growth in electric commodity sales or inflation, as defined by the gross domestic product deflator. The methodology for calculating annual adjustments as well as the schedule for filing annual adjustments defined in Resolution E-3792 shall be continued.

The authorized CEC renewable funding for 2008, as shown below in Table 5, shall be recorded in the PG&E's, SDG&E's, and SCE's applicable Public Purpose Programs balancing accounts. PG&E will record funds in its Public Purpose Program Revenue Adjustment Mechanism; SDGE will record funds in its Renewables Balancing Account; and SCE shall record these funds in its Public Purpose Programs Adjustment Mechanism.

Table 5

Allocation to Renewables Programs

2008-2011

We expect that at least for some portion of 2008, PG&E, SDGE, and SCE will over collect renewables funds since their public purpose program rates that were effective at the beginning of 2008 were set to recover amounts for renewables higher than those authorized by SB 1036. Any over collection of funds for 2008 shall be recorded, with interest, in the IOUs' applicable Public Purpose Program balancing accounts and amortized in the Public Purpose Program rate component no later than the next consolidated rate change. We expect that PG&E's and SDGE's next consolidated rate changes will occur on January 1, 2009. SCE's next consolidated rate change may not occur until early in the first quarter of 2009 since it typically consolidates rate changes after its ERRA forecast proceeding is concluded. For SCE, that may not occur until February 2009.

SB 1036 does not specifically address BVES since the utility voluntarily elected to collect the PGC. In keeping with the legislation, we direct BVES to reduce annual renewable funding to 51.5% of its current annual level, i.e., from $112,000 annually to $54,320 annually (Table 6). Within 30 days of today's date BVES shall reduce rates such that it will collect $54,320 in 2008. The reduction for 2008 shall take into account that BVES has been collecting funding for renewables in rates during the first 4 months of 2008 (from January 1, 2008 through April 30, 2008, assuming the rate change occurs on May 1, 2008), sufficient to fund $112,000 annually. Thus, the revised renewables funding rate for the remaining months of 2008 (May through December 2008) shall be lower than it would have been had the rate change occurred on January 1, 2008. On January 1, 2009, BVES shall reset the renewables rate such that it collects $54,320 for the entire year 2009.

Table 6

Allocation to Renewables Programs

2008-2011

3.1.2. BVES, PG&E, SDGE and SCE must credit unencumbered renewable funds to customers

Public Resource Code §25743, as amended by SB 1036, requires the CEC to transfer remaining unencumbered funds in the New Renewable Resources Account to electrical corporations serving customers subject to the renewable energy public goods charge. Additionally, the Commission must ensure that those funds are allocated in a manner that maximizes the economic benefit to all customer classes that funded the New Renewable Resources Account.

The unencumbered funds transferred from the CEC to the IOUs are:

Table 7

New Renewables Resource Account Funds Transferred²³

The IOUs shall record the funding transferred by the CEC from the New Renewable Resources Account as credits to their applicable Public Purpose Program balancing accounts (i.e., PG&E: the Public Purpose Program Adjustment Mechanism; SDGE: the Renewables Balancing Account; SCE: the Public Purpose Programs Adjustment Mechanism). No later than the next consolidated rate change²⁴, the IOUs shall amortize these credits plus accrued interest in the Public Purpose Program component of rates, with the result of a reduction in this component of their rates. BVES shall revise its preliminary statement to establish an account to record the amounts transferred from the CEC. This account shall be effective on today's date. Amounts recorded in this account shall accrue interest at the 3-month commercial paper rate. Beginning on or before April 1, 2009, BVES shall amortize the amounts recorded in this account in rates over 1 year, to return these funds to customers.

3.2. SB 1036 Establishes a `Cost Limitation' on RPS Contract Costs Expended Above the Market Price Referent (MPR)

3.2.1. The Commission adopts the cost limitation for each IOU

In § 399.15(d), as amended by SB 1036, the Commission is directed to establish a limitation on the total costs expended above the MPR for each electrical corporation. The cost limitation is defined in § 399.15(d)(1):

The cost limitation shall be equal to the amount of funds transferred to each electrical corporation by the Energy Commission pursuant to subdivision (b) of Section 25743 of the Public Resources Code, and the 51.5 percent of the funds which would have been collected through January 1, 2012, from the customers of the electrical corporation based on the renewable energy public goods charge in effect as of January 1, 2007.

Funds transferred from the CEC

The CEC determined the amount transferred to each electrical corporation based on the electrical corporation's respective contribution to the New Renewables Resource Account, minus the amount that was loaned to the General Fund²⁵ (approximately $18.2 million²⁶). Amounts transferred to each utility (Table 7) were approved February 27, 2008 by the CEC.

Funds that "would have been collected"

The Commission, with assistance from the IOUs, calculated the amount representing "51.5 percent of funds which would have been collected" for each utility from January 1, 2008 to January 1, 2012. We used the amount of renewables program funding each IOU collected in 2007 as the starting point and then calculated the subsequent increases in annual funding amounts per § 399.8(d)(2), "at a rate equal to the lesser annual growth in commodity sales or inflation, as defined by the gross domestic product deflator". Annual growth in commodity sales was determined from the Energy Commission's load forecast²⁷ for the particular utility, and inflation was determined from GDP deflator index²⁸. Table 8 shows the annual amounts of Renewables program funding for above-MPR funds (or SEPs) that would have been collected for each utility for 2008 through 2011.

Table 8

Projected "Future SEPs" Funding Amounts for Each Utility

2008-2011

Utility	2008	2009	2010	2011	Projected Totals
BVES	$57,680	$57,680	$57,680	$57,680	$230,720
PG&E	$37,476,875	$37,981,201	$38,479,483	$39,021,374	$152,958,933
SDGE	$6,803,459	$6,908,219	$7,009,355	$7,109,173	$27,830,206
SCE	$31,900,373	$32,434,647	$32,982,478	$33,530,656	$130,848,153

Total cost limitation

Thus, the total cost limitation each IOU may expend above the MPR (Table 9) is the sum of the amounts in Table 7 and Table 8. The Commission will call the total funds that each IOU can expend towards their cost limitation, "Above-MPR Funds" (AMFs). When an advice letter²⁹ is filed requesting approval of cost recovery for above-MPR costs of RPS-eligible power purchase agreements, the above-MPR costs will count towards the IOU's respective cost limitation until the limit has been reached. ³⁰

Table 9

Total Cost Limitation/AMFs for Each Utility

3.2.2. The AMFs Calculator will be used to keep track of funds applied toward cost limitation

The amount of above-MPR funds that are needed for an individual project will be calculated using the `AMFs Calculator'. The AMFs Calculator will be provided to the IOUs by the Energy Division and will be used by each IOU to track the use of and availability of AMFs. IOUs must include the AMF Calculator with each advice letter seeking approval of RPS contracts. The AMFs calculator is based on the SEP calculator used by the CEC, but has been modified by Energy Division for AMFs purposes. Modifications of the SEP spreadsheet include the addition of a summary tab showing the total AMC funding limit and allocations to date for the applicable IOU (AMF Summary tab). The AMF spreadsheet also now has a single input tab (Input Contract Data tab) - the separate tabs for bid price and contract price are no longer necessary with the RPS-eligible contract and AMF request approval occurring simultaneously. Also specific to SEP administration, thus removed, was the ten year payment limitation for SEPs.  Finally, the separate tab calculating the TOD-weighted average contract price was removed, with the calculations being consolidated in the Input and Results tabs.  Energy Division will maintain and modify, if needed, the AMF Calculator.

The AMFs Calculator shows that the cost limitation for each IOU is in 2008$³¹, based on the nominal sum of the funds transferred from the Energy Commission and the estimated revenues that would have been collected through the renewable energy public goods charge, as explained in Section 3.2.1 above. The calculator does not apply any discounting to the estimated collection of funds through 2012 because the mechanism used to establish the limit is based on "virtual" funds that would have been collected - no interest or financing costs are being incurred.

Since the approved AMFs will be allowed into utility rates, the AMFs will be included in utility rates as cost of purchased power. When evaluating purchased power costs for a utility, it is appropriate to apply the utility Weighted Average Cost of Capital (WACC) to discount future payments to a net present value (NPV). This is consistent with standard utility evaluation of supply and demand-side options in resource planning. In addition, credit rating agencies now treat purchased power contracts as equivalent to debt. Thus, although purchased power costs are a pass-through in utility rates, additional financing at the utility WACC may be necessary on the margin to maintain appropriate utility debt to equity ratios. The calculator will sum the 2008 net present value (NPV) ³² of the AMFs awarded for each eligible contract and the total will be applied against the 2008 limit³³ established by the Legislature and defined above.

The total AMFs cost limitation will be reached once the calculator shows no available funds are left³⁴.

3.2.3 IOUs must input appropriate MPR into AMFs Calculator for each proposed RPS project³⁵

The AMFs request, or the amount of funds that could be applied to the cost limitation for a particular contract, is based on the project's levelized $/MWh contract price relative to the appropriate MPR. The AMFs Calculator will compute the project-specific AMFs request based on the appropriate MPR.

Each year the Commission calculates and adopts, by resolution, annual MPR values. The resolutions provide a matrix of MPR values according to a project's commercial online date (COD) and term length. The annual MPR is adopted for use in the annual RPS solicitation. ³⁶ The following guidelines should be followed when choosing the appropriate annual MPR.

1) If a new RPS contract is submitted to the Commission for approval:

a) within 18 months from the close of the solicitation for which the project bid, then the MPR for that solicitation year should be used.

b) more than 18 months from the close of the solicitation³⁷, then the contract is considered a bilateral contract³⁸, and thus not eligible for AMFs.³⁹

2) If a Commission-approved contract is resubmitted to the Commission for approval of contract amendment(s) (e.g. a price amendment), then the most recently adopted MPR as of the contract amendment execution date should be used.⁴⁰ If the Commission deems the amended project substantially different⁴¹ from the originally approved project, however, it will be considered to be a bilateral.

Once the appropriate MPR year is determined, the MPR value depends on the COD and term length. Regarding the former, the Commission will require that the IOUs use a reasonable COD when choosing the comparable MPR value. The COD must be based on a comprehensive project development timeline, which should include all estimated project development milestone dates relevant to interconnection studies, gen-tie and substation construction, transmission network upgrades, financing, site control, permitting and equipment procurement. The Commission reserves the right to use an alternative COD (and thus, MPR) if an IOU's estimate of COD is not reasonable.

When requesting approval for any RPS contract, the AMFs Calculator shall be submitted with the advice letter seeking approval of the contract. The public section of the advice letter should clearly justify the MPR that the contract price was compared to in the AMFs calculation.

3.3. The Commission Adopts Eligibility Criteria and Reasonableness Standards for RPS Projects Applied Toward the Cost Limitation

The Commission will review IOUs' AMFs requests for RPS-eligible PPA costs and will approve or reject these requests based on:

1) whether the project satisfies the eligibility requirements set forth in SB 1036 and by the Commission; and

2) a reasonableness review of the AMFs request; and

3) a review of the availability of AMFs (determined using the `AMFs Calculator').

This assessment will be in addition to the Commission's standard evaluation methodology for IOU advice letters requesting approval for RPS-eligible PPAs, which is based on (but not limited to) consistency with the IOU's procurement plan, adherence to relevant Commission decisions⁴², project viability, contract costs, relevant bid supply curves, and an Independent Evaluator report⁴³. The following eligibility criteria and reasonableness standards for AMFs requests will apply to all RPS projects that have not yet been approved or rejected by the Commission, but will not apply to Commission-approved RPS projects.⁴⁴ This review process will be applied to pending contracts because we have limited above-market funds and have several pending and soon-to-be-filed RPS contracts that will be require AMFs. If the Commission is to consider the use of the funds in totality, the standards must be applied to all pending and forthcoming contracts in order to promote the efficient use of limited above-market funds in a manner that maximizes ratepayer benefit.

3.3.1. SB 1036 and the Commission establish AMFs project eligibility criteria

Pursuant to Pub. Util. Code §399.15(d)(2), all of the following conditions must be met for a project to be eligible to be counted towards the total cost limitation:

1) The contract has been approved by the Commission and was selected through a competitive solicitation pursuant to the requirements of subdivision (d) of Pub. Util. Code Section 399.14.

2) The contract covers a duration of no less than 10 years.

3) The contracted project is a new or repowered facility commencing commercial operations on or after January 1, 2005.⁴⁵

4) No purchases of renewable energy credits may be eligible for consideration as an above-market cost.

5) The above-market costs of a contract do not include any indirect expenses including imbalance energy charges, sale of excess energy, decreased generation from existing resources, or transmission upgrades.

The indirect expenses referred to in condition 5 above are defined as:

· Imbalance energy charges⁴⁶ are the costs associated with compensating generation or load to change output or demand on a real-time basis as requested by the CAISO (or applicable balancing authority) to maintain reliability of the CAISO-controlled grid.  An imbalance energy charge (or credit if the imbalance is negative) is the charge assessed equal to the quantity of imbalance energy multiplied by the applicable CAISO real-time market price for imbalance energy.

· Sale of excess energy⁴⁷ (also referred to as "surplus sales") may occur when excess energy is available from a utility or region for which there is no market at the established rates. 

· Decreased generation from existing resources may be the result of purchased "must-take" energy displacing generation from existing resources. Indirect costs may occur when the displaced generation is less costly than the renewable generation which displaced it.

· Transmission upgrades are the required additions and modifications to the CAISO Controlled Grid and the Distribution System at or beyond the Point of Interconnection. Upgrades maybe Network Upgrades or Distribution Upgrades. An upgrade consists of the facilities at or beyond the point of interconnection (that is those facilities on the participating transmission owner's (PTO's) side of the interconnection) which would not have been necessary but for the interconnection of a new facility. Examples of transmission upgrades include upgrades necessary to remedy short circuit, stability, or thermal overload problems resulting from the interconnection of the new facility to the ISO Controlled Grid, such as reconductoring lines or substation busses, building a new line (but not a tie line), building a new looped substation or increased capacitor banks (i.e., VAR support).

In addition, the Commission adopts the following AMFs eligibility criteria to promote the goals of the RPS program and to ensure that AMFs are used in a cost-effective manner:

1) The contract price is an all-in fixed price for a bundled energy product⁴⁸ from a RPS-eligible facility⁴⁹;

2) The contract is with an RPS-eligible facility that is physically located in California⁵⁰;

3) The project is not otherwise eligible for other Commission-approved funding programs (e.g. Application 07-07-015 pending Commission approval for Emerging Renewable Resource Program (ERRP));

4) The AMFs request can not include firming and shaping costs⁵¹.

3.3.2. Commission will conduct a reasonableness review of each AMFs request

Energy Division will evaluate the reasonableness of the above-market funds requested for an eligible RPS project when reviewing advice letter seeking approval of the RPS contracts. This AMFs review will be in addition to the existing PPA reasonableness review.

Reasonableness review for AMFs-eligible RPS projects seeking Commission approval of a PPA with an above-MPR contract price

There will be no limits (i.e. no cap) on the total AMFs that can be requested for a particular project or solicitation. The Commission will review AMF requests on a case-by-case basis and may approve all above-market contract costs towards the cost limitation or may approve a partial allocation.⁵² At the Commission's discretion, a partial AMFs allocation may be approved for an RPS contract either because the cost limitation does not cover all contract costs or because the Commission deems it reasonable to approve only part of the contract costs towards the cost limitation.

A contract with multiple phases will have all phases reviewed at the same time and count cumulatively towards the same AMFs request.⁵³ Further, linked contracts⁵⁴ will cumulatively count towards the same AMFs request.

These reasonableness review standards are set forth to promote the efficient use of limited above-market funds, in a manner that maximizes ratepayer benefit. For example, viable projects in which the developer is well-informed of all project development costs and that have reasonable online date forecasts would be efficient use of funds to maximize ratepayer benefit. The reasonableness review standards for AMFs requests will be separated into two tiers.

Tier 1: If a project's AMFs request is below $5,000,000⁵⁵, then the contract will be evaluated on whether it satisfies all of the following criteria:

1) The Commission deems the contract reasonable pursuant to existing review methodologies;

2) The contract contains a realistic COD, backed by a comprehensive project development timeline showing how this COD will be achieved. The timeline should include all estimated project development milestone dates relevant to interconnection studies, gen-tie and substation construction, transmission network upgrades, financing, site control, permitting and equipment procurement. The Commission will have the discretion to use another COD (and thus, MPR) if the project's COD estimate is not reasonable;

3) The permitting matrix provided in the advice letter includes: progress towards site control, status of submitted applications, and any risk(s) associated with obtaining a permit;

4) The contract price compares favorably to bid supply curves for:

a) all projects bid into the relevant solicitation;

b) projects utilizing the same technology bid into the relevant solicitation;

c) technology cost curves developed as part of the Renewable Energy Transmission Initiative (RETI).

5) A project-specific Independent Evaluator report reviewing the reasonableness of the PPA as well as the proposed project's financial model.

Tier 2: If a project's AMFs request is greater than $5,000,000, the contract will be evaluated on whether it satisfies all of the following criteria:

1) All of the above criteria;

2) The project has secured 100% site control⁵⁶ or has secured at least 50% site control and can demonstrate that it will obtain 100% site control in a reasonable timeframe with little risk;

3) The project's characteristics fit the IOU's electricity portfolio needs (in addition to RPS need). For example, IOU may demonstrate that the project matches its load profile, provides locational benefits, or provides desired operating flexibility;

4) The project's resource studies are complete and resource is viable;

5) Transmission upgrade needs and costs are reasonably known.

The IOU submitting the power purchase agreement with an above-MPR contract price to the Commission for approval is responsible for providing sufficient information in the advice letter for the Commission to assess whether the contract satisfies the reasonableness review standards described above.

Reasonableness review of Commission-approved contracts seeking contract amendments

RPS projects seeking approval of contract amendments (e.g. price renegotiations) to Commission-approved RPS power purchase agreements may be eligible to request AMFs.⁵⁷ In addition to the reasonableness review applicable to the project as described above, the developer and the IOU requesting approval of amended contract will be required to provide the Commission with financial information about the project. This information must be included in the advice letter⁵⁸ requesting approval of a contract amendment(s) that either a) affects the price of the contract; or b) affects the reasonableness of the price:

1) A reasonable COD backed by a comprehensive project development timeline showing how this COD will be achieved. The timeline should include all estimated project development milestone dates relevant to interconnection studies, gen-tie and substation construction, transmission network upgrades, financing, site control, permitting and equipment procurement. The Commission will have the discretion to use another COD (and thus, MPR) if the project's COD estimate is not reasonable;

2) A permitting matrix, including progress toward site control, status of submitted applications, and any risk associated with obtaining a permit;

3) A list of project costs with any increased line items clearly denoted;

4) Both the original and revised financial models (with rate of return) of the proposed project;

5) Documentation for any price increases for materials, equipment, etc.;

6) An explanation of which MPR the AMFs calculation used⁵⁹ (to be included in the public section of the advice letter);

7) A detailed summary of the IOU's analysis evaluating the reasonableness of the price amendment; and

8) An Independent Evaluator report on the reasonableness of the contract amendment and any price increase, along with their evaluation of required documentation listed above.

3.4 IOUs are not prevented from voluntarily procuring RPS contracts at above-MPR prices that are not counted toward the cost limitation

IOUs can enter into and seek Commission approval for RPS contracts that have contract prices above the MPR even if the project is ineligible for AMFs and/or if the IOU's cost limitation has been reached.⁶⁰ Such projects will be reviewed using the same AMFs reasonableness review criteria listed above (Section 3.3) in addition to the standard evaluation methodology for advice letters requesting approval for renewable PPAs.⁶¹

3.5. RPS projects applied towards the cost limitation may lose AMFs

The Commission has the discretion to reduce or terminate AMFs dedicated to a project that fails to commence and maintain operations consistent with the contractual obligations in the Commission approved PPA.⁶² Also, AMFs awards are subject to Commission review of the IOU's administration of the PPA. If a project fails or has imprudent contract management, the funds will be added back to the IOU's AMFs balance. AMFs may also be revoked if a project fails to meet required milestones⁶³. If the revoked AMFs create a balance in what had been an exhausted cost limitation, the IOU's procurement of eligible renewable energy resources is no longer limited to resources priced at or below the MPR, as allowed in Pub. Util. Code §399.15(d)(3).

Additionally, in the case that a price renegotiation⁶⁴ causes a previously-approved contract to no longer need AMFs, the previously-approved AMFs will revert back to the cost limitation.⁶⁵ As above, if this creates a positive balance in what had been an exhausted cost limitation, the IOU is no longer limited to contracts at or below the MPR in its procurement of renewable energy.

A "true-up" of Commission-approved RPS-eligible projects with AMFs may also reduce or remove AMFs dedicated to a project. If a project's COD is adjusted⁶⁶, then the AMFs of the project may be recalculated. If a true-up creates a positive balance in what had been an exhausted cost limitation, the IOU is no longer limited to contracts at or below the MPR in its procurement of renewable energy.

COMMENTS

Pub. Util. Code § 311(g)(1) provides that this resolution must be served on all parties and subject to at least 30 days public review and comment prior to a vote of the Commission. Section 311(g)(2) provides that this 30-day period may be reduced or waived upon the stipulation of all parties in the proceeding.

The 30-day comment period for the draft of this resolution was neither waived nor reduced. Accordingly, this draft resolution was mailed to parties for comments at least 30 days in advance of being considered by the Commission.

"Public Utilities Code section 311(g)(1) provides that this resolution must be served on all parties and subject to at least 30 days public review and comment prior to a vote of the Commission. Section 311(g)(2) provides that this 30-day period may be reduced or waived upon the stipulation of all parties in the proceeding.

The Commission has chosen to reduce the 30-day waiting period required by Pub. Util. Code section 31l(g)(1) to 29 days because it is in the ratepayer's interest to implement SB 1036. Given the aggressive RPS procurement goals, prompt review of contracts requiring AMF is in the ratepayers best interests. Accordingly, this matter will be placed on the first Commission's agenda twenty-nine days following the mailing of this draft resolution. By stipulation of all parties, comments shall be filed no later than 20 days following the mailing of this draft resolution, reply comments shall be filed no later than 25 days following the mailing, of this draft resolution."

FINDINGS OF FACT

1) The Public Goods Charge (PGC) is a nonbypassable rate component and is part of the electrical corporations' Public Purpose Program Revenue Requirement.

2) Public Utilities Code § 399.8(d) originally required PG&E, SDGE, and SCE to collect $425,500,000 per year through the PGC for three types of Public Purpose Programs (PPP): energy efficiency ($228,000,000), renewable resource energy technology ($135,000,000), and public interest research and development ($62,500,000).

3) Bear Valley Electric Service voluntarily elected to collect the PGC.

4) SB 90 established the New Renewable Resource Account (NRRA), within the Renewable Trust Fund administered by the CEC, to be funded by a portion of the PGC dedicated to renewable resource energy technology programs.

5) SB 1078 and SB 107 authorized the CEC to allocate and award supplemental energy payments from the funds dispersed from the NRRA to cover the above-market costs of certain Renewables Portfolio Standard (RPS) power purchase agreements.

6) In Resolution E-3792, the Commission established how the collection of the renewable resource energy technology PGC funds should be allocated between PG&E, SDG&E, and SCE.

7) Pursuant to § 399.8(d)(2), Resolution E-3792 established a methodology for the IOUs to annually adjust the amount of PGC funds collected, and required the IOUs to file advice letters by March 31^st each year to reflect annual adjustments.

8) SB 1036, effective January 1, 2008, modifies sections of the Public Resources Code and Public Utilities Code, affecting the collection of the PGC, eliminating the NRRA, and requiring the CEC to transfer unencumbered funds in the NRRA back to the electrical corporations that had collected the funds.

9) As a result of SB 1036, the amended Public Utilities Code § 399.8(d) requires the utilities to collect $356 million per year through the PGC for three types of PPPs: energy efficiency ($228,000,000), renewable resource energy technology ($65,500,000), and public interest research and development ($62,500,000).

10) Public Resource Code § 25743, as added by SB 1036, requires the CEC to transfer the remaining unencumbered funds in the NRRA back to the IOUs by March 1, 2008. On February 27, 2008 the CEC approved the transfer of $461,681,784 to Bear Valley Electric Services ($213,016), Pacific Gas & Electric ($229,010,519), San Diego Gas & Electric ($41,198,658), and Southern California Edison ($191,259,591).

11) Public Resource Code Section 25743, as amended by SB 1036, requires the Commission to:

"ensure that each electrical corporation allocates funds received from the Energy Commission...in a manner that maximizes the economic benefit to all customer classes that funded the New Renewable resources Account."

12) SB 1036 also amends Pub. Util. Code § 399.8(d) to eliminate future collection of SEPs money from PG&E, SDGE, and SCE ratepayers by reducing the amount of money that IOUs are to collect for the Renewables programs portion of the PGC.

13) It is reasonable for the Commission to direct BVES to also eliminate future collection of SEPs money.

14) Public Utilities Code § 399.15(d), as amended by SB 1036, requires the Commission to establish, for each electrical corporation, a limitation on the total costs expended above the MPR for the procurement of eligible renewable energy resources procured to satisfy RPS goals.

15) Public Utilities Code § 399.15(d)(1), as amended by SB 1036, directs the cost limitation to equal the amount of funds transferred from the NRRA plus the amount of funds that would have been collected in the NRRA through January 1, 2012.

16) It is reasonable to apply the annual adjustment methodologies set forth in Resolution E-3792 to calculate what BVES, PG&E, SDGE, and SCE would have collected through the PGC and forwarded to the NRRA from January 1, 2008 through January 1, 2012.

17) The funds that BVES, PG&E, SDGE, and SCE would have collected for the NRRA from January 1, 2008 through January 1, 2012 would have been $230,720, $152,958,933, $27,830,206, and $130,848,153 respectively.

18) Public Utilities Code § 399.15(d)(2), as amended by SB 1036, establishes conditions that must be satisfied if the above-market costs of a contract selected by an electrical corporation may be counted toward the above-MPR cost limitation.

19) It is reasonable to assume that IOUs will overcollect PGC funds since each IOU is still collecting amounts as required by Resolution E-3792, even though SB 1036 required the IOUs to stop collecting a portion of the PGC.

20) It is reasonable for the Commission to review advice letters requesting approval of RPS-eligible power purchase agreements (PPAs) such that limited above market funds (AMFs) are used efficiently and in a manner that maximizes ratepayer benefit.

21) It is reasonable for the Independent Evaluator to provide the Commission with analysis regarding the reasonableness of RPS contract costs and project-specific financial models.

CONCLUSIONS OF LAW

1) BVES, PG&E, SDGE and SCE should alter their retail rates to collect the PGC amounts as required by the amended Pub. Util. Code § 399.8(d).

2) Monies for the Renewables and RDD programs should continue to be forwarded quarterly from the utilities to the CEC, along with interest earned on collected funds, consistent with the treatment of these funds in Public Utilities Code § 381

3) Using methodologies set forth in Resolution E-3792, the portion of the PGC that should be collected annually for Renewables by PG&E, SDGE, and SCE from 2008-2012 is:

4) The portion of the PGC that BVES should collect annually from 2008-2012 should be $54,320.

5) BVES, PG&E, SDGE, and SCE should amortize overcollected PGC funds in their applicable public purpose program balancing accounts associated with the reduction in renewables funding required by SB 1036, no later than their next consolidated rate change.

6) BVES, PG&E, SDGE, and SCE should record as credits to their applicable public purpose program balancing accounts, unencumbered renewable funds transferred from the CEC, and amortize these credits, with interest, as reductions to their public purpose program rates no later than their next consolidated rate changes.

7) The cost limitation for above-MPR contract costs (in 2008$) should be $443,736 for BVES, $381,969,452 for PG&E, $69,028,864 for SDGE, and $322,107,744 for SCE.

8) Pursuant to SB 1036, above-MPR costs of a contract may be counted towards the cost limitation if all of the following conditions are satisfied: a) the contract has been approved by the commission and was selected through a competitive solicitation pursuant to the requirements of subdivision (d) of § 399.14; b) contract term is at least 10 years; c) the project is a new or repowered facility commencing commercial operations on or after January 1, 2005; d) no purchases of renewable energy credits may be eligible for consideration as an above-MPR cost; e) the above-MPR costs of a contract do not include any indirect expenses including imbalance energy charges, sale of excess energy, decreased generation from existing resources, or transmission upgrades.

9) To promote the goals of the Renewables Portfolio Standard, above-MPR costs of a contract may be counted towards the cost limitation if all of the following conditions are satisfied: a) the contract price is an all-in, fixed price for a bundled energy product from a RPS-eligible facility; the contract is with an RPS-eligible facility that is physically located in California; 3) the project is not otherwise eligible for other Commission-approved funding programs; and 4) the AMFs request does not include firming and shaping costs.

10) The Commission's review of AMFs requests should be based on reasonableness standards that promote the efficient use of the limited above-market funds, in a manner that maximizes ratepayer benefit.

11) Each advice letter requesting approval of an RPS contract should include an up-to-date AMFs calculator estimating the above-MPR costs of the contract.

12) The Independent Evaluator should provide a project-specific analysis of a project's financial model and above-MPR costs reasonableness based on the AMFs reasonableness review standards set forth herein. This analysis should be included in the advice letter filing requesting Commission approval of the contract.

13) An electrical corporation may request to procure eligible renewable energy resources at above-MPR that are not counted toward the limitation.

THEREFORE IT IS ORDERED THAT:

1) PG&E, SDGE, and SCE shall record, with interest, in their applicable public purpose program balancing accounts, i.e., the Public Purpose Programs Adjustment Mechanism for SCE; the Public Purpose Programs Revenue Adjustment Mechanism for PG&E; and the Renewables Balancing Account for SDGE, a) over collections resulting from 2008 rates recovering more renewables funds than the funding authorized by SB 1036, and b) credits for unencumbered renewables funds transferred from the CEC. The 2008 over collections and the credits for funds transferred from the CEC, including interest, shall be amortized in the public purpose component of rates no later than the utilities' next consolidate rate change. If a utility's next consolidated rate change is delayed beyond March 31, 2009, amortization of these over collections and credits shall occur no later than April 1, 2009.

2) Within 10 days of the effective date of this Resolution, PG&E, SDGE, and SCE shall file advice letters to make all necessary tariff changes to comply with this Order. These advice letters shall also describe how and when each utility intends to amortize over collections and credits for renewable funds transferred from the CEC, as recorded in their applicable public purpose program accounts, and provide an estimate of the dollar amount of these over collections and credits. These advice letters shall be effective on filing subject to Energy Division determining that they are in compliance with this Order.

3) Monies for the Renewables and RDD programs shall continue to be forwarded quarterly to the CEC, along with interest earned on collected funds, consistent with the treatment of these funds in Public Utilities Code § 381.

4) Within 10 days of today's date BVES shall file an advice letter to revise its preliminary statement to establish an account to record unencumbered renewables funds transferred from the CEC back to BVES. The account shall accrue interest at the 3-month commercial paper rate. Beginning on or before April 1, 2009, BVES shall amortize the amounts recorded to this account, including interest, over a 1 year period to return these funds to customers. The advice letter and revised tariffs shall be effective on today's date subject to Energy Division determining that they are in compliance with this Order.

5) Within 30 days of today's date BVES shall file an advice letter to revise its renewables rate such that it collects $54,320 for renewables funding in 2008. The advice letter shall be effective within 30 days of today's date subject to Energy Division determining that it is in compliance with this Order. BVES shall reset the renewables rate beginning January 1, 2009 such that it collects $54,320 in renewables funds over the entire year 2009.

6) PG&E, SDGE, and SCE shall each determine the adjusted target funding amounts that result from the adjustment methodology specified in this Resolution. On or before March 31 of each year ending with 2011, each utility shall file an advice letter with the Commission, for review by the staff, that adjusts the authorizations and allocations found in Table 3 and Table 4, consistent with § 399.8(d)(2).

This Resolution is effective today.

I certify that the foregoing resolution was duly introduced, passed and adopted at a conference of the Public Utilities Commission of the State of California held on April 10, 2008; the following Commissioners voting favorably thereon:

_______________

Paul Clanon

Executive Director

ARNOLD SCHWARZENEGGER, Governor

PUBLIC UTILITIES COMMISSION

505 VAN NESS AVENUE

SAN FRANCISCO, CA 94102-3298

March 12, 2008

I.D. #7466

Draft Resolution E-4160

April 10 Commission Meeting

TO: PARTIES TO DRAFT RESOLUTION E-4160

Enclosed is draft Resolution E-4160 of the Energy Division. It will be on the agenda at the April 10, 2008 Commission meeting. The Commission may then vote on this Resolution or it may postpone a vote until later.

When the Commission votes on a draft Resolution, it may adopt all or part of it as written, amend, modify or set it aside and prepare a different Resolution. Only when the Commission acts does the Resolution become binding on the parties.

Parties may submit comments on the draft Resolution no later than Tuesday, April

1, 2008.

An original and two copies of the comments, with a certificate of service, should be submitted to:

Honesto Gatchalian

Energy Division

California Public Utilities Commission

505 Van Ness Avenue

San Francisco, CA 94102

fax: 415-703-2200

email: jnj@cpuc.ca.gov

An electronic copy of the comments should be submitted to:

Cheryl Lee

Energy Division

cnl@cpuc.ca.gov

Those submitting comments and reply comments must serve a copy of their comments on 1) the entire service list attached to the draft Resolution, 2) all Commissioners, and 3) the Director of the Energy Division.

Comments may be submitted electronically.

Comments shall be limited to ten pages in length plus a subject index listing the recommended changes to the draft Resolution and an appendix setting forth the proposed findings and ordering paragraphs.

Comments shall focus on factual, legal or technical errors in the proposed draft Resolution.

Reply comments shall be served on parties and Energy Division no later than Monday, April 7, 2008 and may also be submitted electronically.

Late submitted comments or reply comments will not be considered.

Paul Douglas

Project and Program Supervisor

Energy Division

Enclosures:

Certificate of Service

Service List: R.06-05-027, R.06-02-012

CERTIFICATE OF SERVICE

I certify that I have by mail this day served a true copy of Draft Resolution E-4160 on all parties in

these filings or their attorneys as shown on the attached list.

Dated March 12, 2008 at San Francisco, California.

____________________

Maria Salinas

NOTICE

Parties should notify the Energy Division, Public Utilities

Commission, 505 Van Ness Avenue, Room 4002

San Francisco, CA 94102, of any change of address to

ensure that they continue to receive documents. You

must indicate the Resolution number on the service list

on which your name appears.

¹ Statutes of 2007, Chapter 685, Perata

² SEPs were to be dispersed from funds held in the New Renewable Resources Account. ,

³ PG&E, SDG&E, and SCE were directed pursuant § 399.8 to collected funds from ratepayers via the public goods charge for the New Renewable Resources Account. BVES requested, and was approved (Resolution E-3556), to also collect funds.

⁴ Public Resources (Pub. Res.) Code 25743 (b) (2)

⁵ "Above-market costs" refers to the portion of the contract price that is greater than the appropriate market price referent (MPR).

⁶ Chapter 516, statutes of 2002, Sher

⁷ Statutes of 2006, Chapter 464, Simitian

⁸ The Commission adopted its MPR methodology in D.04-06-015, as refined by D.05-12-042.

⁹ Statues of 1997, Chapter 905

¹⁰ SB 90 (Statues of 1997, Chapter 905), SB 1038 (Statues of 2002, Chapter 515), and SB 107 (Statutes of 2006, Chapter 464)

¹¹ Chapter 854, Statues of 1996, Brulte

¹² Chapter 1051, Statutes of 2000, Wright

¹³ Commission Resolution E-3792: http://docs.cpuc.ca.gov/PUBLISHED/FINAL_RESOLUTION/22164.htm

¹⁴ except for the Energy Efficiency programs

¹⁵ Commission Resolution E-3792: http://docs.cpuc.ca.gov/PUBLISHED/FINAL_RESOLUTION/22164.htm

¹⁶ Advice Letter 175-E was approved by Resolution E-3556.

¹⁷ http://docs.cpuc.ca.gov/PUBLISHED/FINAL_RESOLUTION/35422.htm

¹⁸ The aggregate PGC funds to be collected for the Renewables programs from all three large IOUs is reduced from $135,000,000 to $65,500,000.

¹⁹ Commission Resolution E-3792: http://docs.cpuc.ca.gov/PUBLISHED/FINAL_RESOLUTION/22164.htm

²⁰ PG&E AL 3022-E (www.pge.com/nots/rates/tariffs/advice/adviceletters/3022-E.pdf)

²¹ SDG&E AL 1885-E ( http://www.sdge.com/tm2/pdf/1885-E.pdf)

²² Edison AL 2113-E ( http://www.pge.com/nots/rates/tariffs/advice/adviceletters/2113-E.pdf)

²³ CEC Resolution 08-0227-9 (Approved February 27, 2008)

²⁴ For PG&E and SDGE, January 1, 2009; for SCE 1^st quarter 2009.

²⁵ Monies were borrowed pursuant to Item 3360-011-0382 of Section 2.00 of the Budget Act of 2002 (Statutes of 2002, Chapter 379)

²⁶ If and when the IOUs portion of the loan is returned, the transferred funds shall be treated in the same manner as outlined above in Section 3.1.2.

²⁷ CEC California Energy Demand, Staff Revision Forecast 2008 to 2018 (November 2007)

²⁸ GDP Price Deflator Index - Global Insight

²⁹ Approval of PPAs are generally requested through advice letters, however, if an application is filed instead of an advice letter, the same requirements in regards to requesting approval of AMFs and above-MPR cost recovery apply.

³⁰ Only if the PPA is found reasonable, project meets AMF eligibility criteria, and AMFs reasonableness standards based on the criteria and standards described in Section 3.3.

³¹ AMFs Calculator, AMFs Summary tab, Cell C3

³² AMFs Calculator, AMFs Summary tab, Cell O44

³³ AMFs Calculator, AMFs Summary tab, Cell C6

³⁴ AMFs Calculator, AMFs Summary tab, Cell C7

³⁵ These are the guidelines for determining the amount of AMFs necessary to cover the contract payments of a proposed RPS project. The actual approval of these funds is contingent on the eligibility of the contract and the reasonableness review outlined in Section 3.3.2.

³⁶ MPRs are calculated annually to ensure we are using values that most accurately reflect current market conditions, especially related to natural gas prices, forward energy price curves, and capital cost escalation

³⁷ A competitive solicitation reflects the current competitive market at the time of the solicitation. If contract negotiations extend for a significant amount of time (defined as 18 months) after a solicitation closes, then the resulting negotiated contract is no longer reflective of the market at the time of the solicitation and thus should no longer be considered part of that solicitation.

³⁸ Bilateral contracts are defined as contracts negotiated outside of a competitive solicitation process. Bilateral reasonableness standards are being resolved in R.06-02-012. Once the Commission has adopted such standards in R.06-02-012, please refer to the relevant decision to determine which MPR should be used to evaluate bilateral contracts.

³⁹ According to Pub. Util. Code § 399.15(d)(2), only contracts negotiated as part of a competitive solicitation can be counted toward the cost limitation.

⁴⁰ Because of the potential incentive for sellers to renegotiate contract prices, submission of additional data is required for contract amendments that affect the reasonableness of the price. See Section 3.3.2.

⁴¹ "substantially different" may be determined based on one (or a combination of) the following: change in project location, project size, contract term, contract price, fuel type, and/or online date

⁴² e.g., the `least-cost best-fit' decision (D.04-07-029), the `standard terms and conditions' decision (D.07-11-025), the `minimum quantity for short-term contracts' decision (D.07-05-028), etc.

⁴³ D.06-05-039, page 46

⁴⁴ Eligibility criteria and AMFs reasonableness review do not apply to Commission-approved power purchase agreements, unless an amendment affecting the contract price or AMFs is filed.

⁴⁵ When SB 1036 amended Public Resource Code § 25743, the definition of "repowered" was deleted from statute. As a result, the Commission defers to the CEC RPS Eligibility Guidebook for the definition of "repowered".

⁴⁶ Sources of imbalance energy include regulation, spinning and non-spinning reserves, replacement reserve, and energy from other generating units that are able to respond to the California Independent System Operator's (CAISO) request for more or less energy.

⁴⁷ Excess generation may be caused by having too much baseload or must-take generation (e.g., nuclear, spill avoiding hydro, regulatory must-take) operating.

⁴⁸ Bundled RPS contracts include the procurement of energy, resource adequacy and green attributes.

⁴⁹ A project seeking AMFs allocation must have received its pre-certification for RPS eligibility from the CEC.

⁵⁰ "The program objective shall be to increase, in the near term, the quantity of California's electricity generated by in-state renewable electricity generation facilities, while protecting system reliability, fostering resource diversity, and obtaining the greatest environmental benefits for California residents." (Public Resource Code § 25740.5(c))

⁵¹ The MPR calculation does not include firming or shaping costs, thus, it would not be a viable tool for evaluating above-market contract costs of such projects. So, the IOU must provide the all-in price with and without firming and shaping.

⁵² An IOU can request a partial allocation in the advice letter.

⁵³ AMFs needed for each phase should be calculated separately if the phases' commercial online dates or prices differ, since different MPRs will be applicable to different phases. The sum of the AMFs calculated for each phase will then equal the total AMFs request.

⁵⁴ Linked contracts, as defined in D.07-01-039: The contracts specify the same powerplant as the primary delivery source or, for an unspecified source, they are with the same counter-party; and they are negotiated or executed within any three consecutive-month period, except if entered into as a result of separate RFOs and the contract from the earlier RFO is executed before the later RFO has received any bids (either indicative or final).

⁵⁵ AMFs requests will be calculated as the NPV of above-MPR contract costs, in 2008$

⁵⁶ Site control may be in the form of a title, lease, or other form of written proof of right to develop or gain access to the land required for project.

⁵⁷ The same eligibility criteria described in Section 3.3.1 are applicable.

⁵⁸ If the requested information is confidential pursuant to Commission confidentiality rules, it may be provided in confidential appendices to the advice letter or application. Otherwise, it must be contained in the public version of the filing.

⁵⁹ See Section 3.2.3 for rules on calculating a project's AMFs allocation request

⁶⁰ Pub. Util. Code §399.15(d)(4): "Nothing in this section prevents an electrical corporation from voluntarily proposing to procure eligible renewable energy resources at above-market prices that are not counted toward the cost limitation. Any voluntary procurement involving above-market costs shall be subject to commission approval prior to the expense being recovered in rates."

⁶¹ The standard evaluation is based on (but not limited to) consistency with the IOU's procurement plan, adherence to relevant Commission decisions, project viability and an Independent Evaluator report.

⁶² Similar language existed as part of Section 25743 of the Public Resource Code prior to SB 1036.

⁶³ Failure to meet required milestones will be based on biannual Project Development Status Reports.

⁶⁴ See Section 3.3.2.2 for reasonableness review of Commission-approved contracts seeking contract amendments with above MPR costs

⁶⁵ If a reduced amount of AMFs are needed, then the difference will revert back to the cost limitation.

⁶⁶ Adjustment of CODs will be based on biannual Project Development Status Reports and/or PPA amendment filings.