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PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

ENERGY DIVISION RESOLUTION E-4199

RESOLUTION

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

__________________________________________________________

1. Summary 33

2. Background 44

3. Discussion 99

Comments 5050

Findings 6464

ORDER 6868

1. SUMMARY

In this Resolution we implement the remaining requirements of Senate Bill (SB) 10361, which modifies the cost containment provisions 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. In place of the SEPs program, 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. 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 electrical corporations are now required to seek above-market cost recovery from the Commission for eligible RPS contracts.

As a result, this Resolution establishes the above-MPR funds (AMFs) program by adopting:

2. BACKGROUND

In order to contain the total costs of the RPS program, SB 1078 established the supplemental energy payments (SEPs) program. SEPs were funds collected from ratepayers as part of the Public Goods Charge (PGC) and remitted to the CEC.5 The CEC was authorized to allocate SEPs to cover above-market costs of long-term RPS-eligible contracts executed through a competitive solicitation.6 The statute allowed electrical corporations to limit their RPS procurement to contracts that were at or below market prices if these funds were exhausted.7

In order to calculate the above-market costs of renewable energy contracts, § 399.15(c) requires the Commission to adopt a methodology to estimate the long-term market price of electricity. The Commission adopted a market price referent (MPR) to represent 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 contracts will be considered per se reasonable, and can be recovered in rates; pursuant to SB 1078, SEPs were to cover the costs above the MPR.

Table 1

Required Yearly Program Funding Starting 200213

($ million)

EE Programs

$228.0

Renewables

$135.0

RDD

$62.5

Total

$425.5

Table 2

Allocation to Programs by Utility, 2002-2011

($ million)

Utility

EE Programs

Renewables

RDD

Totals

PG&E

$106.0

$67.7

$31.4

$205.1

SDG&E

$32.0

$12.0

$5.5

$49.5

SCE

$90.0

$55.3

$25.6

$170.9

Totals

$228.0

$135.0

$62.5

$425.5

Of the PGC that were collected for Renewables programs, 51.5% were allocated to the SEP fund.

SB 1036 modifies the mechanism for awarding above-market costs to eligible renewable energy contracts negotiated through competitive solicitations. The bill eliminates the CEC's authorization to administer the SEP funds.14 SB 1036 also requires the CEC to transfer all unencumbered funds in the New Renewable Resources Account (NRRA) back to the electrical corporations serving customers subject to the PGC, allocated among retail sellers on the basis of retail sales of electricity.15 SB 1036 further reduces the amount of PGC collected for Renewables programs (from $135 to $65.5 million), so that SEPs are no longer collected.16

The Commission must establish a "cost limitation" for each electrical corporation to replace the SEP program as the RPS cost containment mechanism. The cost limitation is "a limitation on the total costs expended above the MPR for the procurement of eligible renewable energy resources procured to satisfy RPS goals".17 As a result, rather than renewable generators seeking SEPs from the CEC, electrical corporations are now required to seek Commission approval for the eligible18 above-market RPS contract costs up to the utility's cost limitation.

The Commission mailed Draft Resolution E-416019 on March 12, 2008 to implement SB 1036.20 On March 26, 2008, a Joint Party Request for Bifurcation of Issues Addressed in Draft Resolution E-4160 (Joint Party Request) was sent to the Commission's Executive Director.21 The Joint Party Request asked the Commission to bifurcate the non-controversial ratemaking issues22 of the resolution from the policy-related issues23, and include only the former in Resolution E-4160.

The Executive Director responded to the Joint Party Request in a letter (March 28, 2008) stating that the final resolution for Commission consideration would include only the rate-changing issues and that Energy Division would hold a workshop on SB 1036 policy-related issues.

3. DISCUSSION

This Resolution implements SB 1036 in the following ways:

3.1.1 Party Comments

DRA, TURN27, and CCP agree SB 1036 implementation rules should be designed to promote the statutory goals of the RPS program.28 DRA and TURN suggest that because AMFs are limited, the Commission should prioritize the allocation of AMFs to viable least-cost best-fit (LCBF) projects and to in-state RPS resources. They argue that implementing prescriptive eligibility rules and review standards to allocate AMFs only to such projects will promote the goals of the RPS program and maximize ratepayer benefit.

3.1.2 Discussion

Pursuant to SB 1036, the Commission must establish a cost limitation for each electrical corporation. The inputs for calculating the cost limitation were set forth in SB 1036 and codified 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.

Because the cost limitation is defined to include only the funds transferred by the CEC to electrical corporations serving customers that paid the renewable energy PGC plus the PGC funds that would have been collected for SEPs, we are setting cost limitations only for those electrical corporations to which funds have been transferred (namely BVES, PG&E, SDG&E, and SCE; henceforth "the IOUs").

Amount of Funds Transferred

Pursuant to SB 103632, the CEC was required to transfer the remaining unencumbered funds in the NRRA to electrical corporations serving customers subject to the PGC. Accordingly, the CEC approved CEC Resolution 08-0227-9 (February 27, 2008), which transferred each electrical corporation's respective contribution to the NRRA minus the amount that was loaned to the General Fund33, as listed in Table 3:

Table 3

NRRA Funds Transferred

Utility

Amount of Funds

Transferred

BVES

$ 213,016

PG&E

$ 229,010,519

SDG&E

$ 41,198,658

SCE

$ 191,259,591

Funds that "would have been collected"

Table 4

Projected "Future SEPs" Funding Amounts for Each Utility

2008-2011

Utility

2008

2009

2010

2011

Projected Totals

BVES36

$57,680

$57,680

$57,680

$57,680

$115,360

PG&E

$37,476,875

$37,981,201

$38,479,483

$39,021,374

$152,958,933

SDG&E

$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

Table 5

Total Cost Limitation/AMFs for Each Utility

Utility

Amount (2008$)

BVES

$ 328,376

PG&E

$ 381,969,452

SDG&E

$ 69,028,864

SCE

$ 322,107,744

Total

$ 773,434,436

SB 1036 sets forth five criteria that a contract must satisfy be applied to an IOU's cost limitation (i.e. to be allocated AMFs):37

In the post-workshop ruling, parties were asked: 1) whether or not the Commission should implement additional AMFs eligibility criteria and 2) how the Commission should quantify and subtract the indirect expenses identified in criterion #5 from the AMFs request. We will address the latter in Section 3.5.5, where we set forth rules related to calculating a project's AMFs need.

3.3.1 Parties' Comments

TURN, DRA, and CCP support the adoption of additional eligibility criteria. In particular, TURN and DRA support an additional eligibility criterion requiring projects to be located in California.

The Joint Parties and CEERT recommend having the five criteria set forth in § 399.15(d)(2) as the only eligibility criteria, and oppose an additional eligibility criterion requiring projects to be located in California.39 They instead recommend that AMFs eligibility should extend to any renewable facility that meets the definition of "in-state renewable electricity facility" as defined in Public Resource Code § 25741(b).40

3.3.2 Discussion

The Commission is responsible for maintaining reasonable rates for ratepayers, while ensuring safe and reliable service. Accordingly, when an IOU files for approval of an RPS contract, the Commission evaluates whether the proposed contract price is reasonable, the project is viable, the contract terms and conditions comply with Commission decisions, the project complies with the IOU's approved procurement plan, and if the project is, on balance, in the best interest of the ratepayer. Parties have recognized that there are additional connotations to reviewing project viability and evaluating the reasonableness of a contract with an above-market price that is eligible for AMFs. In this section, we discuss what standards should be used when evaluating the project viability and price of an above-MPR RPS contract that is eligible for AMFs. Additionally, we adopt rules for evaluating above-MPR, AMFs-eligible contracts that are re-submitted for approval of an amendment affecting the price of a Commission-approved contract.

Project viability

If a project that requires AMFs is approved but never comes online, the project has "tied up" AMFs and may have prevented other viable RPS projects that need AMFs from being developed. This is particularly problematic for implementation because AMFs are limited and there is a statutory "waiver" that allows an IOU to limit RPS procurement to contracts that are at or below the MPR, after the IOU has exhausted its AMFs.42

Price reasonableness

While RPS contracts are considered per se reasonable if priced at or below the MPR,43 Commission decisions and RPS statute are silent on what the price reasonableness standard is for an above-MPR contract. Adopting clear, transparent standards for price reasonableness of projects priced above the MPR will streamline review and simplify administration of AMFs. The following are examples of criteria that could be used to evaluate the reasonableness of above-MPR contract prices:

Review standards for amended contracts

In the post-workshop ruling requesting comments, the Commission asked if there should be any different viability and price review standards for proposed contracts versus those requesting approval of an amendment affecting a contract price already approved by the Commission.44

3.4.1 Party Comments

Project viability

Price reasonableness

The Joint Parties say that any RPS contract price should be considered reasonable if it successfully competes against the market in an RPS solicitation. The Joint Parties and TURN agree that the most reliable and relevant measures for evaluating the value of an RPS contract are the IOU's least-cost best-fit (LCBF) bid evaluation rankings and bid supply curves from recent solicitations. CEERT agrees with the Joint Parties that all contracts, regardless of the duration of the contract term or whether it was negotiated bilaterally or through a competitive solicitation, "should be subject to the same reasonableness review for cost recovery in rates".51 CEERT further suggests that this evaluation can be based on the LCBF bid evaluation, bid and cost supply curves from recent solicitations, and technology cost benchmarks.52 However, the Joint Parties and TURN recommend against using technology cost curves from the Renewable Energy Transmission Initiative (RETI) or cash flow models.53 SCE claims that because of the confidential nature of cash flow models, requiring them might deter developers from negotiating with the IOUs. PG&E and CalWEA/LSA assert that using cash flow models implies that the Commission is evaluating the reasonableness of a developer's profit margin, which is not part of the Commission's authority. CalWEA/LSA offers an alternative - have the independent evaluator (IE) comment on the reasonableness of the proposed contract price from a market perspective.

Review standards for amended contracts

Several parties propose how contract amendments affecting a contract price already approved by the Commission should be reviewed. SDG&E, supported by DRA, recommends the use of cash flow models, asserting that developers should be required to justify their new price by providing a thorough review of all project costs since the new price is no longer comparable to the solicitation it was initially competitive with. TURN suggests that either the project is completely re-evaluated against the most recent solicitation's bid supply curves or that the developer provides financial models and documentation concerning project costs. SCE and PG&E assert that contract price amendments should not require any additional information or a new IE report and that the Commission should review price amendments on a case-by-case basis. SCE says that requiring additional documentation would delay the contract approval process. CalWEA/LSA do not support looking at a developer's financial information.

3.4.2 Discussion54

Project viability

While the Commission reserves judgment on the review standards for bilateral contracts55, we agree with the Joint Parties and CEERT that all above-MPR contracts negotiated through a competitive solicitation should be reviewed in the same manner regardless of whether the IOU's cost limitation has been reached.56 This is in the best interest of the ratepayer, helps limit the total costs of the RPS program, and promotes viable renewable energy development to meet RPS goals.

The Commission agrees with TURN that project viability is an important issue to consider in reviewing above-MPR AMFs-eligible contracts because the above-MPR funds are limited and there are real and significant implications if the funds are exhausted. However, as PG&E points out, in the ACR responding to the Decision Granting a Certificate of Public Convenience to the Sunrise Powerlink Transmission Project (D.08-12-048 ), the Commission recognizes that project viability is a critical issue to address for the entire RPS program. The ACR includes a Staff Proposal addressing standardized criteria for assessing project viability within the IOUs' bid evaluation process, the relationship between project viability and Commission contract review, and the alignment of flexible compliance rules and project viability. Because the Commission is considering adoption of more comprehensive rules in R.08-08-009, it no longer makes sense to establish another (potentially different) level of project viability review, nor to prejudge here what we might decide in the broader context there.

Price reasonableness

The Commission agrees with the Joint Parties and TURN that we should evaluate above-MPR contract prices against existing review standards, including bid supply curves from the IOU's recent solicitation and the project's least-cost best-fit ranking relative to the other projects that bid into the solicitation.57 We also accept PG&E's suggestion that the MPR used to evaluate the reasonableness of a contract price should be the same as the MPR used to calculate the project's AMFs need (See Section 3.5.3.2 for guidelines on choosing the appropriate MPR). Energy Division staff may also use RETI cost estimates to assess whether the contract price reflects recent engineering estimates of renewable project costs.58 The Commission should not require that IOUs assess the rate impact of each above-MPR contract nor require that all above-MPR contracts submit cash flow models. However, Energy Division staff always has the option on a case-by-case basis to request data to substantiate the contract price, if for example, the price does not compare favorably to bid supply curves. We also support CEERT's proposal to require the project-specific IE report to discuss the project's price reasonableness from a market perspective. Given the scope of an IE's role, however, the IE should not be required to compare a proposed RPS contract generally to "the market", but instead an IE report must contain information on whether IOU's bid evaluation accurately reflects the project's market valuation and whether the project's market valuation is competitive relative to the IOU's other options in the most recent solicitation. In fact, confidential IE reports usually already contain this information.59

Review standards for amended contracts

As is current practice, if a developer requests an amendment that affects the contract price of an approved contract, the IOU should re-evaluate the competitiveness of the amended project as compared to the projects that the IOU is negotiating and to its most recent shortlist. The IOU must provide a sufficient showing in the advice letter that the amended contract is competitive based on current market data. Additionally, contracts that are re-filed with the Commission for approval of an amendment that affects an approved contract's price have to explain why the contract change is needed, and provide all relevant data to justify the change.

Party comments are split on whether cash flow models should be required to justify contract price amendments.60 The Commission agrees with SDG&E that while bid supply curves are most appropriate to evaluate contracts the first time they are submitted, if a project has increased its price, the solicitation information may no longer be relevant. The Commission has already begun requesting, and receiving, cash flow models for contracts requesting price amendments. We disagree with SCE's comment that additional documentation would delay the contract approval process because establishing upfront expectations, rather than requesting additional information through data requests after an advice letter is filed, will shorten and streamline the approval process. We are also not convinced that developers will be deterred from participating in California's RPS if cash flow models are required for price amendments, and nonetheless we find that it prudent to require the information in order to protect ratepayers from unnecessary price increases.

Thus, the developer must provide the Commission and the IE with cash flow models, both the original reflecting the price in the original contract and the latest version, for projects that are re-filed with the Commission for approval of a price amendment if the new contract price is above the MPR and the contract is eligible for AMFs.61 The confidential project-specific IE report must, at a minimum, include its evaluation of the new price based on the project's market valuation as compared to the bids in the IOU's most recent solicitation, a review of the cash flow model, and an evaluation of the change in model inputs. An IE's conclusions must not be based on whether the developer's rate of return is reasonable, but rather whether the change in model inputs are reasonable and justify the price change. (Please see Appendix A for an example of the inputs that may be required for the cash flow model.)

The CEC developed a "SEPs Spreadsheet" that was used to calculate the SEPs required for each RPS project. Similarly, the Commission has created an "AMFs Calculator". This Calculator will be used to determine a contract's AMFs need and to keep track of an IOU's AMFs balance.

In addition to adopting an AMFs Calculator, we must establish the following guidelines to be able calculate the inputs for the Calculator:

3.5.1. AMFs Calculator

The AMFs Calculator is based on the SEP Spreadsheet used by the CEC, but was modified by Energy Division. The AMFs Calculator now includes an `AMFs Summary' tab showing an IOU's cost limitation, prior AMFs allocations, and AMFs balance. The Calculator also has only one input tab (`Input Contract Data' tab) because it is no longer necessary to have separate tabs for bid price and contract price since the contract review and AMFs request will now occur simultaneously. Also, the ten year payment limitation for SEPs has been removed.  Finally, the separate tab calculating the time of delivery (TOD)-weighted average contract price has been removed because the calculations are consolidated in the Input and Results tabs.

IOUs must include the AMFs Calculator with every advice letter seeking approval of an RPS contract.62,63 The AMFs Calculator will be maintained and modified, as needed, by the Energy Division.

The Calculator can be found on the RPS website.64

3.5.2 AMFs Request - nominal or discounted

In the AMFs Calculator proposed in Resolution E-4160, the AMFs requests were discounted by the utility weighted average cost of capital (WACC) to calculate a net present value of the request. This value was then compared to the nominally calculated cost limitation to determine the AMFs need.65 The rationale for calculating the requests in this manner was:

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.66

3.5.2.1 Party Comments

3.5.2.2 Discussion

The Commission agrees with comments that the cost limitation and AMFs requests calculations should logically be treated in the same manner. No party provides rationale otherwise. Because we do not find it prudent to discount the estimated SEPs funds that would have been collected through 2011 (see Section 3.2), the AMFs Calculator will also not apply any discounting to the AMFs requests. Thus, we adopt PG&E and SCE's jointly proposed AMFs Calculator methodology68 - the AMFs Calculator will sum the nominal value of the AMFs requested for each eligible contract69 and the total will be applied against the nominally-calculated cost limitation70 established by the Legislature and defined above in Section 3.2. This is consistent with our guiding principle of implementing simple AMFs rules. The total AMFs cost limitation will be reached once the AMFs Calculator shows no available funds are left.71

3.5.3 Appropriate MPR for AMFs Request

While a new set of MPRs are approved for each annual solicitation, contracts are not always executed shortly after the solicitation closes. In the post-workshop ruling, parties were asked whether a project that is still in negotiations 18 months or more after the close of the solicitation should be required to bid into a new solicitation, be considered a bilateral, or be compared to a more recent MPR. The ruling also asked what MPR should be used if a contract amends its price and is resubmitted for Commission approval.

Contract online date

Once the MPR solicitation year is determined, Energy Division uses the contract's COD to select the appropriate MPR value as provided by the MPR matrix.74 This can be difficult for two reasons. First, while the developer and IOU negotiate a COD for the contract, the actual start date may occur later if contractual terms and conditions allow delays to the COD (e.g. due to delays in completing construction of a new transmission line or in extending the federal production tax credit). Many times this contractual flexibility is necessary because there are uncertainties regarding project development when a contract is executed. Second, sometimes it is apparent that the contractual COD is not realistic given, for example, known transmission construction schedules or the time it takes to receive permit approvals. Parties were asked in the post-workshop ruling whether and how the Commission should determine a realistic COD if there are uncertainties in the contract or it is apparent to Energy Division that the contractual COD is not realistic.

3.5.3.1 Party Comments

Solicitation year

The Joint Parties and CCP recommend using the most recently adopted MPR and time of delivery (TOD) factors75 to calculate the AMFs request for contracts with prolonged negotiations. The Joint Parties do not recommend that a contract be considered a bilateral if the contract negotiations are prolonged because, they say, this would penalize a project (i.e. by making it ineligible for AMFs). They also do not think that the Commission should require a project to re-bid into a new solicitation. Joint Parties justify both of these positions saying that it might not be the developer's fault that negotiations were complex, and they wouldn't want to prolong project development as a result. PG&E further states that many projects may benefit from negotiations extending beyond 18 months. The Joint Parties note that the benefit of using a more recent MPR is that it more accurately reflects current energy prices.

DRA supports considering projects with prolonged negotiations as bilaterals to ensure that AMFs are used in a cost-effective manner. TURN disagrees with DRA, saying that this would provide an incentive for contracts to delay negotiations to sign high priced contracts because there is no cost limitation for bilateral contracts. TURN instead recommends that projects in negotiations for more than 18 months be required to re-bid into the next solicitation to provide the appropriate motivation to expedite contract negotiation.

Joint Parties also recommend that the most recent MPR and TODs are used for contracts resubmitted for approval of a price amendment.

Contract online date

The Joint Parties recommend that the appropriate COD to use in AMFs calculations is the COD in the contract. They argue that the counterparties make an effort to identify a realistic COD during contract negotiations, and they say that if the Commission finds that the project is not viable as written, the Commission should reject the contract. SDG&E notes that it would be difficult to develop an objective method for the Commission to determine an alternate "realistic" COD. Joint Parties also say that if a project COD changes, the Commission will receive the information in the semi-annual project development status reports. No parties present an alternative recommendation or proposal for determining the appropriate COD.

3.5.3.2 Discussion

Solicitation year

We agree that the projects that are bid into a solicitation and execute a contract after prolonged negotiations should be compared to the most recent MPR and TODs. Using a more recent MPR is preferable because it more accurately reflects current energy prices and the market that the project should be evaluated against. At the same time, the IOU should evaluate whether the contract is still competitive with newer bids and provide the Commission with this evaluation in its advice letter.

We acknowledge TURN's concern that there may be unintended incentives for developers to delay negotiations if a newer MPR is higher. However, we find that this does not outweigh the risk of requiring projects to be re-bid into a new solicitation, which would further prolong negotiations and project development, and may unfairly penalize developers. This is consistent with all of our guiding principles, in particular enhancing seller certainty and promoting renewable development. Of course, an IOU may ask a counterparty to re-bid into a new solicitation.

Thus:

Contract online date

To be consistent with our principle of simple and streamlined AMFs rules, the Commission will use the contractual COD in an AMFs calculation. While it would not be difficult to determine that a COD is unrealistic, we agree with SDG&E that it may be complex to determine an alternate COD that is "realistic". The Commission already requires IOUs to provide information on project milestones and transmission upgrade information in the advice letter, so the Commission can assess whether the contractual online date is realistic. And, if the Commission finds the project not viable, for instance due to an unrealistic COD, then the PPA and AMFs request can be rejected or conditionally approved.

3.5.4 Calculating a contract's levelized price

Contract prices can be structured in a number of different ways, but the price must be translated into a levelized price in order to calculate a project's AMFs need. If the contract price is fixed or escalating at a pre-established rate, then it is relatively simple to calculate the levelized price. However, if the contract price is indexed to unknown future equipment prices, forward energy prices, or inflation, it is impossible to calculate the actual levelized contract price. It may also be difficult to calculate the costs of a contract even if the contract price is fixed if project specifications (e.g. capacity or capacity factor) are not finalized until later in the project development process or if the price or online date depends on the final results of transmission or resource studies.

3.5.4.1 Party Comments

The Joint Parties recommend that, in the cases when the contract price is indexed, such as to forward energy prices, the Consumer Price Index (CPI), or equipment prices, that a forecast (submitted by the IOU with the advice letter) be used by the Commission to estimate the AMFs for the contract. Also, the Joint Parties request that if a contract's specifications are not finalized at the time of the advice letter filing, the Commission should use an estimated value of the maximum amount of AMFs that could be needed.

While TURN does find it reasonable to award AMFs to projects indexed to equipment prices, TURN and DRA recommend against awarding any AMFs to a contract whose price is indexed to forward fossil energy prices since that pricing structure does not promote price stability, a primary goal of the RPS program. TURN also argues that there is no valid reason why a renewable contract should have future prices indexed to the CPI. PG&E, supported by SCE, alternatively asserts that a contract with an indexed price may be the most cost effective way to allocate cost risk between the buyer and seller. SCE says that there is no legal support for excluding projects with certain types of indexed pricing from receiving AMFs.

3.5.4.2 Discussion

The Commission agrees that the most prudent way to calculate a levelized price for a contract whose exact price is uncertain is to use a best-guess estimate of what the maximum price may be. It would not be prudent to count a lesser amount towards the cost limitation because if too few AMFs are allocated to a project, then the IOU may have to come back to the Commission requesting more, which would be inconsistent with our goals to create streamlined AMFs rules and to enhance seller certainty. Thus, if a contract has an indexed price or if the contract allows for a range in contract specifications, the IOU must identify in the advice letter the possible range of levelized prices and AMFs that the project could require. The advice letter must include a calculation of the maximum levelized price, a description of the calculation methodology and assumptions, and all relevant documentation used to develop forecasts of CPI, equipment prices, or energy prices. The IOU must submit an AMFs Calculator for the maximum levelized price from this range. To the greatest extent possible, the IOU should include the methodology it uses to calculate the levelized price in the public version of the advice letter, but in accordance with D.06-06-066, the AMFs Calculator and all price-sensitive information related to the calculation may be submitted confidentially.

While the Commission agrees with DRA and TURN that indexing a long-term RPS contract price to forward fossil energy prices does not necessarily promote stable energy prices nor necessarily benefit the ratepayer, we will not make such projects ineligible for AMFs. The eligibility of RPS contracts indexed to fossil energy prices is beyond the scope of this Resolution.

3.5.5.1 Party comments

Indirect costs

The Joint Parties comment that it is unusual for indirect costs to be included in an RPS contract, and thus they are unlikely to be included in an AMFs calculation. They do not provide a methodology to calculate the expenses if included in the contract, but instead say that if it were to occur, the Commission should be able to identify it and handle it on a case-by-case basis.

Other direct costs

SCE points out that firming and shaping costs of out-of-state RPS contracts should also be included in AMFs requests both because such costs are inherently included in the MPR calculation and pursuant to Public Resources Code Section 25741, firming and shaping costs are directly attributable to delivering the RPS-eligible energy from out-of-state facilities.

3.5.5.2 Discussion

Indirect costs

We do not accept the Joint Parties' suggestion to identify indirect costs on a case-by-case basis. Instead, we find it reasonable to require an IOU to identify whether a contract's AMFs request includes any indirect costs, such as those identified in § 399.15(d)(2), in each advice letter requesting review and approval of an RPS contract.77 If such costs are included in the contract, then the IOU must include in the advice letter: 1) a calculation that subtracts the indirect expenses from the contract's total above-market costs and 2) a written description of the methodology and any supporting documentation used for the requested calculation.78 In the contract-specific IE report accompanying the advice letter, the IE must also identify whether the contract includes indirect expenses, review the IOU's calculation, if applicable, and report whether the IE agrees with the IOU's assessment of indirect expenses.

Other direct costs

IOUs should identify in the advice letter all costs associated with the contractual terms and conditions. However, at this time, only the firming and shaping costs associated with delivering intermittent out-of-state generation to California should be added to the AMFs calculation. This enables a fair and equitable comparison of in-state and out-of-state contracts to the MPR. The firming and shaping costs should be identified and calculated whether they are included in the RPS contract or not. These costs will be considered part of the AMFs request.

These rules apply to all contracts, including those already Commission-approved.

The Commission must resolve the following issues related to the administration of AMFs:

3.6.1 Party Comments

A. Application of eligible contracts to cost limitation

PG&E, SCE, SDG&E, and TURN comment that all eligible above-MPR projects should be applied toward the cost limitation until the AMFs are exhausted. CalWEA/LSA and DRA disagree, saying that counting a contract toward the cost limitation is optional.79 CalWEA/LSA, citing §399.15(d)(4)80, says that IOUs should be able to choose whether an eligible contract requests AMFs or not. DRA cites §399.15(d)(2)81, arguing that the Commission should be able to choose whether an AMFs-eligible contract gets applied to the cost limitation.82 TURN and SCE recognize that the statutory language may allow such optionality, however, both parties and PG&E argue that overall statutory directive in SB 1078 was to limit total costs, and thus, it would not be consistent with the legislative intent to approve but not apply AMFs-eligible contracts to the cost limitation.

B. Partial allocation

The Joint Parties and TURN recommend that a project should either receive all of the AMFs it requests or be rejected; the Commission should not approve only partial amount of requested AMFs. TURN points out that if the Commission finds that a contract is overpriced it should be rejected outright instead of being given a partial award. DRA disagrees, saying that the Commission should have the discretion to award less than the requested amount of AMFs to any particular contract.

The Joint Parties recommend that within 30 days of the adoption of the AMFs rules, each IOU file an accounting of its AMFs balance to-date with previously approved contracts credited against their cost limitation. The IOUs and TURN request that this filing be kept confidential, and CalWEA/LSA recommend that it should be public.

D. True-ups

Joint Parties recognize that AMFs true-ups may be necessary if a contract is terminated or if a project's online date, capacity, or price changes from the original CPUC-approved contract. PG&E and SCE recognize that while some contract amendments must be approved by the Commission (and thus, the Commission will approve the AMFs true-up in the resolution), other amendments can be executed as a matter of contract administration. In the latter case, PG&E suggests that the IOU confidentially notify Energy Division within 30 days of the contract amendment execution to adjust the AMFs balance in a timely manner after the amendment takes effect. SCE instead recommends that there be a "true-up" after each semi-annual Project Development Status Report (PDSR)83 filing and that the Energy Division can update the IOUs' AMFs balances through a letter or other report issued after the filing.

E. Confidentiality of AMFs needs and AMFs balance

PG&E, SCE, SDG&E, and TURN assert that an IOU's AMFs balance should be kept confidential to ensure that bidders pricing decisions are not improperly influenced. PG&E and SCE also contend that the AMFs balance is entitled to confidential treatment under D.06-06-066.

PG&E, SDG&E and TURN also think that it should remain confidential when an IOU exhausts its AMFs. PG&E and SDG&E recommend that the resolution approving the contract that exhausts the IOU's AMFs should confidentially note that the IOU has reached its cost limitation. SCE, however, does not oppose publicly disclosing the fact that an IOU's AMFs are exhausted because they say that this would not make confidential contract pricing information public. SCE recommends that once an IOU exhausts its AMFs, the Energy Division Director should send a letter to the relevant IOU indicating the AMFs are exhausted and copy the letter to the relevant service lists.

CalWEA/LSA asserts that neither an AMFs balance nor the exhaustion of AMFs should be confidential. They reason that confidential price information can remain protected if the Commission releases aggregated AMFs balance updates (rather than balance updates after each contract is approved towards the cost limitation). They cite D.06-06-066, which says that there should be greater access to RPS information "due to the strong public interest in the RPS program".84 Also, CalWEA/LSA counters the assertion that disclosing AMFs balances will improperly influence bidding behavior. They argue that bids are influenced by a myriad of factors and an IOU's diligence in evaluating the viability and reasonableness of bids is a better mechanism for normalizing bid prices than redacting AMFs balances. Further, CalWEA/LSA asserts that having such information publicly available is in the public interest because it enables parties to lobby the Legislature for more AMFs, if necessary.

F. Revoking AMFs

PG&E, SCE, and SDG&E recommend that AMFs should only be revoked if the contract is terminated. While CalWEA/LSA agrees that AMFs should be revoked when a contract is terminated, they also support the Commission revoking AMFs when a developer misses a milestone deadline so that non-viable projects do not tie-up AMFs.

3.6.2 Discussion

A. Application of eligible contracts to cost limitation

We agree with PG&E, SCE, SDG&E, and TURN that all AMFs-eligible contracts approved by the Commission must be credited against an IOU's cost limitation. This is consistent with the intent of the statute and our guiding principle of limiting the total costs of the RPS program. IOUs can voluntarily procure AMFs-eligible RPS contracts above the MPR and not apply them to the cost limitation only after AMFs are exhausted. However, IOUs can voluntarily procure above-MPR renewable energy contracts that are not AMFs-eligible (e.g. bilaterals) before the cost limitation is reached.

B. Partial allocation

We agree that the Commission should not award only a portion of the necessary AMFs to a project. If the Commission does not think that the price is reasonable or that the project is viable, then the project can be rejected or conditionally approved. This will promote developer certainty and maintain our goal for streamlined AMFs rules. If, however, the amount of AMFs remaining for an IOU is insufficient to cover the full AMFs request of a project, then the IOU should identify in its advice letter whether it is willing to voluntarily procure the total costs of the contract, even if they exceed the IOU's cost limitation; in this case, the project's above-MPR costs will only be partially covered by AMFs.85

The Commission has already approved AMFs-eligible, above-MPR RPS contracts for each IOU and has stated in the resolutions that the contracts would be applied to the IOU's cost limitation. In order to determine the IOUs' current AMFs balances, we adopt the Joint Parties' recommendation that within 30 days of the adoption of this Resolution, each IOU must confidentially file AMFs Calculators accounting of its AMFs balance with previous credits against its cost limitation. A qualitative report should accompany the Calculator explaining the calculations (pursuant to the rules in this Resolution) for each approved contract already applied to the cost limitation.

D. True-ups

In order to promote streamlined rules and not true-up AMFs balances continually throughout the year, we adopt SCE's proposal for AMFs true-ups. If a project's specifications has changed since the Commission approved the project, but the revision falls under contract administration,86 the change should be identified in the semi-annual PDSRs. Each utility must submit with their PDSRs updated AMFs Calculators, and all relevant documentation, for the projects that have modified AMFs needs. Because of the timing of the approval of this Resolution, the IOUs should begin truing-up AMFs needs in the August 2009 compliance filing.

However, if a contract amendment changes a project's AMFs, then Commission approval is needed, and the IOU will include an updated AMFs Calculator with the advice letter requesting approval of the contract amendment. If the amendment is approved, the AMFs balance will be updated in a confidential appendix of the Resolution approving the contract amendment.87 While PG&E would like have a more timely update to an AMFs balance when a contract change is implemented administratively, we find that this would create too much complexity. It is simpler to handle all such true-ups as part of the PDSRs.

If as a result of a true-up, an IOU goes from having a zero AMFs balance to having a positive AMFs balance, the newly available AMFs should be available for RPS contracts that have not yet been executed. The AMFs should not go to already-executed contracts because the utility has already voluntarily procured those above-MPR costs.

E. Confidentiality of projects' AMFs needs and IOUs' AMFs balances

Because RPS contract prices are confidential per D.06-06-066, a project's specific AMFs need must also be kept confidential. As a result, we can not release an IOU's AMFs balance after each contract is applied toward an IOU's cost limitation. However, this rationale does not justify keeping the balance confidential in all circumstances. We agree with CalWEA/LSA that it is prudent for the market and Legislature to have regular updates on each IOU's AMFs balance. We also agree that the LCBF evaluation methodology, and the contract review standards established in this Resolution (which are equivalent for eligible above-MPR contracts regardless of whether the cost limitation has been reached) should create sufficient incentives for developers to set their respective bid prices at competitive levels; thus, releasing an IOU's AMFs balance shouldn't negatively affect bidding behavior. We also agree with SCE that confidential information can not be gleaned from publicly notifying parties when an IOU's AMFs have been exhausted. Publicly noticing AMFs balances on a regular basis and IOUs' AMFs balances is consistent with our goals of enhancing seller certainty and promoting renewable development.

Thus, after IOUs' semi-annual PDSRs are reviewed by staff, the Energy Division Director will send a letter, copied to the relevant service lists, to each IOU stating their AMFs balance and whether their cost limitation has been reached.88 The Director will also send an AMFs balance letter if the approval of a contract exhausts an IOU's cost limitation. In either of these situations, if such a letter would result in disclosing public information, the IOU can request89 that the letter not be served on the service lists. The public letters will be posted to the RPS website.

F. Revoking AMFs

While we agree with CalWEA/LSA that it is not desirable for non-viable projects that miss their milestones to tie-up AMFs, we have previously recognized that the intent of SB 1036 was to ensure the financeability of above-MPR contracts. As a result, the Commission should not be able to revoke AMFs before a contract is terminated pursuant to the contractual terms and conditions.90 If either the IOU or developer terminates the contract, this should be noted in the PDSR and the funds will be applied back to the IOU's AMFs balance.

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 30-day comment period for the draft of this resolution was neither waived nor reduced. This draft resolution was mailed to parties for comments on January 16, 2009. Comments were received on February 5, 2009 from CalWEA, CEERT, DRA, PG&E, SCE, and SDG&E. Reply comments were received on February 10, 2009 from PG&E and SCE.

3.7.1 Guiding Principles

CEERT asks the Commission to correct the Draft Resolution's characterization of CEERT's position on implementing SB 1036

CEERT asserts that that the Draft Resolution did not correctly characterize its position on RPS reasonableness review, specifically related to its proposed "overarching goal" and "priorities for allocating and administering limited above-market funds."91 CEERT explains that the Draft Resolution addressed a subset of its proposal on reasonableness review standards for AMFs-eligible RPS contracts without providing the overall context that CEERT offered a number of recommendations as part of an integrated proposal.

We have revised the discussion in the Resolution to properly characterize CEERT's integrated proposal. Also, CEERT's assertion that

the Commission's priority should be to determine whether `the Legislature intend[ed] that, once an IOU's AMFs are exhausted, the Commission was relieved of its obligation to ensure that the 20% RPS target or CARB's emission reduction measure of 33% renewables will or can be met92,

identifies an issue in the legislation, but not an issue related to administering the cost limitation as defined by SB 1036. Because this Resolution is only establishing the cost limitations for each IOU and setting rules for the administration of the above-market funds, the issue does not need to be addressed in this Resolution.

SCE requests that AMFs be allocated on a "first-come, first-served" basis

SCE disagrees with the way in which the Draft Resolution interprets the meaning of the phrase "first-come, first-served" and the implication on AMFs allocation. The Draft Resolution says that awarding AMFs on a first-come, first-served basis "would imply that the Commission would approve AMFs to any project that requests them", but SCE instead thinks that it would ensure that the "CPUC will not delay the approval of AMF-eligible contracts that meet the CPUC's review standards to wait for contracts that may better meet some undefined criteria (which may never be executed)"93.

We have modified the discussion regarding guiding principles and no longer discuss whether eligible above-MPR contracts will be allocated AMFs on a first-come, first-served basis. However, we do accept SCE and PG&E's request to not delay reviewing and writing a draft resolution for one AMFs-eligible contract in order to wait and see what other contracts are in the pipeline. Rather, we will evaluate each contract on its own merit as is discussed in Section 3.4.

3.7.2 Eligibility Criteria

DRA recommends that the Commission adopt additional eligibility requirements

DRA argues that the Commission should not have rejected its recommendation to make out-of-state projects ineligible for AMFs. DRA asserts that California should not pursue out-of-state renewables if they are above the MPR because this will discriminate against in-state technologies and that rules of statutory construction provide the Commission with the discretion to adopt eligibility rules in addition to those established in § 399.15(d)(2).

In response, SCE comments that the statutory definition of "in-state facilities" includes eligible out-of-state facilities, and thus, the statute already considers that such facilities meet the goals of the RPS program. SCE says DRA's assertion that allowing out-of-state resources to be eligible for AMFs would discriminate against in-state resources "is wholly without merit" and DRA "offers no support for this strange contention".94 SCE further states that the Commission should reject DRA's comments because they do not raise any new arguments. Similarly, PG&E points out that making out-of-state facilities ineligible for AMFs is inconsistent with the goal of SB 1036, which aims to place a cost cap on the program. PG&E also agrees with the Draft Resolution, which says that the value of a facility's location should instead be considered in the least-cost best-fit evaluation of RPS bids.

The Commission rejects DRA's request to limit AMFs to in-state projects. The statute does not put limitations on the allocation of AMFs to projects based on location, and as stated in the Draft Resolution, "We suggest that if parties think that IOUs should value certain types or characteristics of projects (e.g. location) over others, that they pursue it in the revisit of the least-cost best-fit methodology in R.08-08-009."

3.7.3 Reasonableness Review Standards

PG&E and SCE recommend eliminating project viability review standards

PG&E objects to the project viability review standards for projects requesting over $50 million in AMFs because the Commission has offered a "timely alternative means of considering the viability of signed contracts" in the Assigned Commissioner's Ruling in R.08-08-009 (February 3, 2009).95 SCE argues that "there is no support in the statue or legislative history for more stringent standards of review for contracts requiring AMFs".96 Both PG&E and SCE argue that the additional review standards are arbitrary and won't ensure that an RPS project is viable. CEERT additionally requests clarification on how this Resolution impacts other rulemakings addressing project viability of RPS contracts.

The Commission accepts PG&E and SCE's recommendation to eliminate additional reasonableness review standards for contracts requesting over $50 million in AMFs. Given the release of the ACR, it is now duplicative to address project viability in this Resolution. The Commission instead is considering adoption of more comprehensive rules in R.08-08-009 focusing on how the IOUs and the Commission will address project viability in the bid evaluation process and flexible compliance rules for all RPS contracts; thus, it no longer makes sense to establish another (potentially different) level of project viability review, nor to prejudge here what we might decide in the broader context there.

SDG&E requests the use of rate impact assessments

PG&E and SDG&E request that the IE's role not be expanded

The IOUs object to the determination in the Draft Resolution to require the IE report for an eligible above-MPR contract to discuss the reasonableness of the contract price from a market perspective. PG&E and SDG&E assert that the IE is only responsible for ensuring that the RPS solicitation process is conducted fairly and is consistent with Commission requirements.

In recognition of the IOUs' concern, the discussion has been revised. As noted in the discussion, the IE reports generally contain an assessment of whether the IOU evaluated the market valuation of each project fairly and if the project's price and value compares favorably to other bids in the solicitation.

CalWEA and SCE request that the Commission not require developers to provide confidential financial information

The Draft Resolution says that Energy Division can ask for financial information on a case-by-case basis for `first-time' contracts, and for price reopeners, the developer must supply a cash flow model and a corresponding IE report. CalWEA asks that the Commission eliminate both provisions, and SCE objects to the latter. Both parties reason that the requirements would deter developers from participating in California's RPS solicitations. SCE further argues that, at a minimum, the Commission should only require cash flow models for contracts that request a price amendment and are both eligible for AMFs and above the MPR because it is out of scope of this Resolution to impose new requirements on price amendments that are ineligible for AMFs.

PG&E agrees with SCE that the cash flow model requirement may discourage some developers, but says that in the short-term this requirement will only affect developers that already have RPS contracts. To address SCE's concern, PG&E suggests that we revisit the cash flow model requirement after each IOU gains experience with the requirement.

We reject CalWEA's request to eliminate the ability of staff to request a project's financial information because the Resolution is simply clarifying and preserving an option that the Energy Division already has. Also, we reject CalWEA and SCE's request to eliminate the obligation for contracts with price amendments to provide a cash flow model and IE report. However, we do accept SCE's requested modification that the requirement only applies to AMFs-eligible contracts that are above the MPR. Also, we note that the Staff Proposal in the February 3, 2009 ACR in R.08-08-009 proposes to adopt rules applying to all RPS contracts requesting price amendments.97

PG&E and SDG&E request modifications to cash flow model requirement for amended contracts

In response to the Draft Resolution's requirement for developers requesting price amendments to submit a cash flow model, PG&E says that developers should provide information that would "assure that its proposed price increase reflects net changes in costs, rather than just an increase in profits".98 PG&E also identifies a couple discrepancies between the text on this issue and the Ordering Paragraph related to what entity (IOU or developer) must provide the cash flow model and what the IE is required to review (amended price and/or change in model inputs). SDG&E suggests that, in addition to requiring the developer to provide all relevant data to justify a price change, the Commission should require the model inputs to be "verifiable source data" and should evaluate the reasonableness of the developer's rate of return. SCE opposes this request on the grounds that it is not clear what "verifiable source data" would be required. 

We agree with PG&E that the purpose of requiring the cash flow model is to assess whether the "proposed price increase reflects net changes in costs, rather than just an increase in profits".99 Thus, we clarify that the developer must provide both its original100 and new cash flow models so that the IE and Energy Division can review the changes in model inputs that motivated the price amendment.

We reject SDG&E's proposals. First, SDG&E proposes that the data submitted by developers be "verifiable source data that substantiates the major costs included in the developer's pro forma".  While the Commission is certainly interested in obtaining accurate information, SCE raises a valid point in that it is not clear what verifiable source data may be.  Accordingly, we will not adopt SDG&E's recommendation, with the caveat that we expect information submitted to the Commission to be accurate.  If we determine that we are not obtaining adequate information, the Commission may revisit this issue. Second, while SDG&E requests that the Commission evaluate whether the developer's rate of return is acceptable, it is not relevant because the purpose of requiring a cash flow model is to determine whether the price amendment is reasonable, given the change in project costs since the original contract was executed.

SCE asserts that certain requirements may disclose confidential information

3.7.4 AMFs Request Calculation

DRA objects to including firming and shaping costs in the AMFs calculation

DRA "opposes the treatment of firming and shaping costs as direct costs" even when such costs are included in a separate arrangement from the RPS contracts.102 DRA asserts that the Draft Resolution does not explain why firming and shaping is not an indirect cost. SCE and PG&E respond that firming and shaping costs are directly attributable to delivering the RPS-eligible energy.

The Commission agrees with SCE and PG&E and rejects DRA's request. A bundled RPS contract, by definition, requires that RPS-eligible energy that is generated at a facility, with its first point of connection to the transmission network outside of California, to be scheduled for consumption by California end-use retail customers (Public Resources Code 25741). Thus, the cost associated with firming and shaping out-of-state intermittent energy, so that it can be transferred across balancing authority areas and into California, is a direct cost of the RPS contract, regardless of whether the firming and shaping agreement is part of the RPS contract with the generator or is in a separate contract.

DRA asserts that using AMFs for non-fixed price contracts is against the law

DRA claims that the "Commission has no authority to award AMFs to contracts indexed to forward energy prices under SB 1036" because a "contract indexed to an unknown factor, such as forward energy prices would fail to further the RPS goal of promoting stable energy prices".103 SCE responds that an indexed price could be in the best interests of the ratepayer. DRA also says that the Commission may be illegally delegating its discretionary authority to a third party because the Draft Resolution requires the IOU to calculate best-guess estimate of what the maximum levelized contract price may be. PG&E and SCE disagree, arguing that the IOU's estimated price is only temporary to provide information to help the Commission make a decision.

The Commission rejects DRA's request because it is outside the scope of this resolution. Neither the statute nor a Commission decision requires all RPS contracts to promote price stability, and policy decisions, such as deciding whether RPS contracts can or should be indexed to forward energy prices, must be addressed by the Commission in a decision. Also, we agree with PG&E and SCE that the Commission is not delegating its discretionary authority to a third party by requiring the IOU to estimate a contract's levelized price. The Commission is only asking the IOU to provide the Commission with information and we will ultimately decide and approve the AMFs allocation for a project in a resolution.

DRA requests modification to treatment of contracts executed after protracted negotiations

PG&E and SCE request modifications to AMFs Calculator

PG&E requests clarification on the use of AMFs funds from cancelled projects

PG&E requests that the Commission clarify the allocation of AMFs that become available due to contract termination. PG&E would prefer that the newly available AMFs be allocated to Commission-approved contracts that are AMFs-eligible but that did not receive AMFs because the IOU had already reached its cost limitation.

The Commission clarifies that it will reallocate AMFs associated with a terminated contract to new contracts. In other words, the Commission will allocate the funds to AMFs-eligible above-MPR contracts that have not yet been executed, in the order of contract execution. The funds should not be allocated to Commission-approved contracts because an IOU has already voluntarily decided to procure the above-market costs beyond their cost limitation and the Commission has already deemed the contract reasonable.

3.7.5 Other

CEERT asks that the Commission implement SB 1036 via decision

CEERT claims that "The Draft Resolution is not the appropriate procedural vehicle for reaching key legal and policy determinations on the RPS program".106 CEERT notes that there was a Joint Party Request to bifurcate certain issues out of Draft Resolution E-4160, which was granted by the Commission, and in the request Joint Parties said that "the implementation of SB 1036 may require more formal processes, if these issues cannot be appropriately addressed through workshops". While CEERT did not respond to the pre-workshop question about whether there were "any material factual disputes that may require an evidentiary hearing", CEERT does say that its post-workshop comments included discussion of issues that CEERT believed required "statutory interpretation and construction".

Both PG&E and SCE disagree with CEERT that the Draft Resolution be withdrawn in order to resolve the issues in a decision. PG&E says that the Energy Division workshop notice "provided sufficient public notice and opportunity to be heard and the Commission has compiled an adequate record for informed decision-making".107

We reject CEERT's proposal. The Commission is not required to hold evidentiary hearings before considering the Resolution, because implementing SB 1036 does not require the Commission to determine material issues of fact.  When asked, for example, no party identified any disputed issue of material fact. Further, no party asked for the opportunity to separately file briefs arguing disputed interpretations of law. The Resolution implements state law mandates into the existing, Commission approved, RPS procurement framework.  Additionally, the Resolution implementing SB 1036 does not modify past Commission Decisions.  Thus, implementing SB 1036 via Resolution is appropriate and a formal proceeding is not required. 

CEERT requests clarification on Draft Resolution's relationship to other decisions

CEERT comments that the Draft Resolution "makes broad determinations on reasonableness review standards and project viability that will apply to all RPS contracts" even though the review standards for bilateral and short-term RPS contracts are "still pending in the formal RPS rulemakings".108 CEERT questions what changes or additions are proposed by the Draft Resolution to existing reasonableness standards for RPS contracts.

We have clarified throughout this Resolution that the standards established here are only for contracts that are AMFs-eligible and above the MPR, whether the contract is being submitted for approval for the first time or for subsequent amendments that affect the price of the contract. The Commission will address review standards for bilateral and short-term RPS contracts in R.06-02-012 or R.08-08-009, as appropriate.

FINDINGS

ORDER

Therefore it is ordered that:

1) The following cost limitations shall be applied to Bear Valley Electric Service (BVES), Pacific Gas and Electric (PG&E), San Diego Gas & Electric (SDG&E), and Southern California Edison (SCE):

Utility

Amount (2008$)

BVES

$ 328,376

PG&E

$ 381,969,452

SDG&E

$ 69,028,864

SCE

$ 322,107,744

Total

$ 773,434,436

2) When BVES, PG&E, SDG&E, or SCE submits an advice letter or application for approval of a power purchase agreement (PPA) for renewable energy or an amendment to an already-approved PPA that is above the market price referent (MPR), the utility shall identify whether the PPA complies with the statutory eligibility criteria codified in § 399.15(d)(2).

3) The utilities shall provide sufficient information in their advice letter filings to enable the Commission to evaluate the contract price and viability of each renewable energy contract that was negotiated through a competitive solicitation and that has a contract price above the MPR using the criteria set forth in Section 3.4.2.

4) When BVES, PG&E, SDG&E, or SCE submits an advice letter or application for approval of a PPA for renewable energy (including an amendment affecting the price of a Commission-approved PPA) that was negotiated through a competitive solicitation and for which the contract price is above the MPR, the utility shall include a report from an independent evaluator (IE) discussing the whether IOU's bid evaluation accurately reflects the project's market valuation and whether the project's market valuation is competitive relative to the IOU's other options in the most recent solicitation.

5) When BVES, PG&E, SDG&E, or SCE submits an advice letter or application for approval of an amendment to a Commission-approved PPA for renewable energy and the PPA is eligible for AMFs and has an above-MPR contract price, the utility shall provide sufficient information on why the price change is needed and how the contract compares to offers from the most recent solicitation. Also, the developer shall provide an IE and the Commission with cash flow models for the contract's original price and proposed new price as well as the information needed to assure that its proposed price increase reflects net changes in costs. The IE shall submit a confidential report with the advice letter or application that includes the IE's review of the models and an evaluation of the change in model inputs.

6) When BVES, PG&E, SDG&E, or SCE submits an advice letter or application for approval of a PPA for renewable energy or an amendment affecting a Commission-approved PPA price, the utility shall submit an AMFs Calculator and supporting documents with the filing, as described in Section 3.5.

7) All eligible contracts shall be applied to a utility's cost limitation until it is exhausted.

8) IF BVES, PG&E, SDG&E, or SCE submits an advice letter or application for approval of a PPA (or a price amendment to a Commission-approved PPA) with above-market costs, and there are insufficient AMFs to support the total AMFs need or the PPA is ineligible for AMFs, the utility shall inform the Commission whether it would voluntarily procure the above-MPR costs.

9) When the utilities submit semi-annual Project Development Status Reports, starting with the August 2009 Report, they shall each update the contract specifications for each contract that has been applied to their cost limitations and provide AMFs Calculators and all necessary documentation for any contracts whose AMFs need has been modified.

10) The Director of Energy Division shall notify utilities and relevant service lists about what each utility's AMFs balance is after Energy Division Staff reviews each utility's Project Development Status Report, unless doing so would release confidential information protected by D.06-06-066.

11) The Director of Energy Division shall notify utilities and relevant service lists if a utility exhausts its AMFs.

12) In order to calculate each utility's AMFs balance, within 30 days of the effective date of this resolution, PG&E, SDG&E, and SCE shall each confidentially submit to the Director of Energy Division AMFs Calculators and all relevant documentation, as described in Section 3.5, for each Commission-approved renewable energy contract and pending renewable energy contract with a contract price above the MPR.

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 March 12, 2009; the following Commissioners voting favorably thereon:

MICHAEL R. PEEVEY

PRESIDENT

DIAN M. GRUENEICH

JOHN A. BOHN

RACHELLE B. CHONG

TIMOTHY ALAN SIMON

Commissioners

Appendix A

1. Turbine equipment costs

2. Land-use-related costs (acquisition costs or annual lease payments)

3. Construction cost for the balance of each unit and tower

4. Site development costs (roads, transmission collection system, metering, monitoring)

5.Permitting costs

6. Financing costs (fees and projected accrued interest up to commercial operation)

7. All other project development costs not included in the above categories (and a description of what they are)

8. Project capital structure (percentages of debt/equity/other)

9. Debt rate

10. Project book value at commercial operation

11. Project tax value at commercial operation

12. Annual revenues

13. Annual operating and maintenance costs

14. Annual spare parts expenses and capital replacement activities

15. Annual federal tax obligations before PTCs

16. Annual PTCs

17. Annual federal tax payments

18. Annual deferred taxes

19. Annual state tax payments

20. Annual local tax payments

21. Annual property tax payments

22. Annual tax depreciation

23. Annual debt service (principal and interest payments, shown separately)

24. All other annual costs not included in the above categories (and a description of what they are)

25. Annual equity cash flow

26. Return on equity

1 Statutes of 2007, Chapter 685, Perata

2 Statutes of 2002, Chapter 516, Sher

3 Unless otherwise indicated, all subsequent citations to sections refer to the Public Utilities Code.

4 Statutes of 2006, Chapter 464, Simitian

5 Assembly Bill (AB) 1890 authorized the electrical corporations to collect the PGC in rates for the period from 1998 to March 2002. AB 995 reauthorized the funding through January 1, 2012. The PGC is a non-bypassable rate component intended to fund in part energy efficiency, renewable resource energy technology, and public interest research and development. A portion of the PGC funds are remitted to the CEC, and prior to SB 1036, some of the funds went to the New Renewables Resource Account (NRRA) in the Renewable Resource Trust Fund to fund SEPs.

6 To receive SEPs, the developer of a Commission-approved SEP-eligible contract applied to the CEC for SEPs. The SEPs need was calculated as the net present value of the above-market costs, accounting for the IOU's time-of-delivery (TOD) profile, over the term of the contract. No RPS contract ever received SEPs from the CEC.

7 § 399.15(b)(4)

8 D.04-06-015, as modified by D.05-12-042.

9 PG&E, SDG&E, and SCE were directed pursuant § 399.8 to collect the PGC. BVES requested, and was approved (Resolution E-3556 and E-3856), to also collect funds.

10 except for the Energy Efficiency programs

11 http://docs.cpuc.ca.gov/PUBLISHED/FINAL_RESOLUTION/22164.htm

12 Resolution E-3792 also describes how § 399.8 requires adjustments to this funding in future years at a rate equal to the lesser of the annual growth in electric commodity sales or inflation, as defined by the national Gross Domestic Product (GPP) deflator.

13 § 399.8(d)(1)

14 Formerly § 399.13(c)

15 Public Resources Code § 25743

16 § 399.8(d)(1)

17 § 399.15(d). 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.

18 SB 1036 sets forth eligibility criteria for the RPS contracts that may be counted towards the cost limitation (§399.15(d)(2)).

19 http://docs.cpuc.ca.gov/published/COMMENT_RESOLUTION/80089.htm

20 Comments on Draft Resolution E-4160 were filed by Pacific Gas & Electric Company (PG&E), San Diego Gas and Electric Company (SDG&E), Southern California Edison (SCE), Sempra Utilities, California Manufacturers & Technology Association (CMTA), California Large Energy Consumers Association (CLECA), The Center for Energy Efficiency and Renewable Technologies (CEERT), Central California Power (CCP), and jointly by California Wind Energy Association (CalWEA) and Concentrated Solar Power Alliance (CSPA). Reply comments were filed by CEERT, PG&E, SDG&E and SCE.

21 Joint Parties include SCE, SDG&E, PG&E, CEERT, and CalWEA

22 1. Directing IOUs to adjust their respective Public Purpose Program rate components collecting PGC;
2. Directing IOUs to amortize funds transferred from the New Renewable Resources Account, administered by the CEC, in their PPP rate component;
3. Directing BVES to establish an account to record unencumbered renewable funds transferred from the CEC back to BVES.

23 1. Setting a limitation on total costs expended above the MPR
2. Establishing AMFs eligibility criteria
3. Adopting guidelines for approving requests for above-market funds.

24 http://docs.cpuc.ca.gov/PUBLISHED/FINAL_RESOLUTION/81476.htm

25 On May 1, 2008 Energy Division circulated a request for pre-workshop comments. Comments were received from PG&E, SDG&E, SCE, CEERT, CalWEA and Large-Scale Solar Association (LSA), Division of Ratepayer Advocates (DRA), The Utilities Reform Network (TURN), and Coral Power L.L.C.

26 Comments were timely received from PG&E, SDG&E, SCE, CEERT, CCP, CalWEA/LSA, DRA, TURN, and jointly by PG&E, SDG&E, SCE, and CalWEA/LSA (Joint Parties). Reply comments were received from CalWEA/LSA, CEERT, PG&E, SCE, and TURN.

27 TURN also says that the most relevant goals for the SEPs program were providing a cost cap for ratepayer-funded renewable energy and supporting renewable project financing by ensuring ratepayer funding for above-market costs.

28 More specifically: promote stable electricity prices, protect public health, improve environmental quality, stimulate sustainable economic development, create new employment opportunities, and reduce reliance on imported fuels (§399.11(b))

29 SB 1036 § 1

30 CEERT's post-workshop Comments, July 8, 2008, p. 3

31 CEERT also proposes that the Commission's highest priority for the implementation of SB 1036 should be to determine whether the "Legislature intend[ed] that, once an IOU's AMFs are exhausted, the Commission was relieved of its obligation to ensure that the 20% RPS target or CARB's emission reduction measure of 33% renewables will or can be met?" (Post-Workshop comments, page 6). In other words, CEERT asks the Commission to address the issue of whether the statutory language effectively makes the RPS program a voluntary program (at the discretion of the IOUs) as opposed to a mandatory one.

32 Public Resources Code § 25743

33 Approximately $18.2 million was borrowed pursuant to Item 3360-011-0382 of Section 2.00 of the Budget Act of 2002 (Statutes of 2002, Chapter 379). If and when the IOUs' portion of the loan is returned, the transferred funds shall be treated in the same manner as outlined in Resolution E-4160.

34 § 399.8(d)(2)

35 Staff used the annual growth in commodity sales figures from the Energy Commission's load forecast (CEC California Energy Demand, Staff Revision Forecast 2008 to 2018 (November 2007)) for the particular utility, and inflation figures were determined from GDP deflator index (GDP Price Deflator Index - Global Insight).

36 BVES' PGC collection did not escalate per Pub. Util. § 399.8(d)(2). Therefore, estimated future collections are assumed also to not escalate.

37 § 399.15(d)(2). As discussed previously, this is a subset of the rules that governed the SEPs program.

38 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".

39 In the Joint Parties' Comments (July 8, 2008) it is noted that Shell Energy America (US) LP supports this point.

40 Joint Parties' Comments Regarding Implementation of SB 1036 (July 8, 2008), p.10

41 The eligibility criteria must apply to Commission-approved RPS projects as well as pending and future above-MPR RPS projects.

42 § 399.15(d)(3)

43 D.04-06-015 ( http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/37383.pdf)

44 We also asked whether the standards should apply to contracts that are not eligible for AMFs (e.g. bilateral and short-term contracts), however, this issue will instead be addressed in R.06-02-012 or R.08-08-009, as appropriate.

45 "Project viability is currently assessed through consideration of several factors, including, but not limited to, the extent to which the project involves a technology that is mature and proven, whether the seller has site control, the status of financing and permitting, whether resource studies have been prepared, whether adequate transmission is available and the existence of performance obligations." (Joint Party post-workshop comments, July 8, 2008, p. 11)

46 TURN also suggests that if a project is above the MPR and AMFs have been exhausted, that the project is either rejected or treated as a bilateral. TURN includes a detailed proposal for the review of above-MPR bilateral contracts. (TURN post-workshop comments, July 8, 2008, p. 10.) We reject TURN's first request because the statute explicitly provides IOUs with the discretion to voluntarily procure above-MPR projects that are not counted toward the cost limitation, and all issues related to bilateral contracts will be addressed in R.06-02-012 or R.08-08-009.

47 In its initial comments, TURN recommends that the viability assessment include: a project-specific IE report reviewing the reasonableness of the PPA and project's financial model; demonstration of 50 percent site control at the time of contract approval and demonstration that 100 percent site control will be obtained in a reasonable time frame; and completion of resource studies showing that the resource is viable. However, in reply comments, TURN revises its recommendation "in appreciation of the practical reality that it is difficult for project developers to demonstrate viability through documentation of their financial model and with resource studies." ((TURN post-workshop reply comments, p. 4))

48 TURN post-workshop comments, July 8, 2008, p. 6

49 PG&E's comments on Draft Resolution E-4199, July 8, 2008, p. 2

50 Joint Parties' post-workshop comments, July 8, 2008, p. 8

51 CEERT post-workshop comments, July 8, 2008, p. 11

52 This suggestion is part of an integrated set of reasonableness review requirements in CEERT's Post-Workshop comments. CEERT also recommends an alternative price review methodology for an above-MPR contract price: if the price is below a pre-determined reasonable renewable energy credit (REC) price plus MPR it should be considered reasonable. (p. 11-12)

53 In its pre-workshop comments, TURN supported the use of cash flow models, but in its post-workshop comments amended its position saying that it isn't valuable to only require cash flow models for above-MPR contracts.

54 The reasonableness standards set forth in this section will only apply to RPS projects that have not yet been approved or rejected by the Commission. However, the review will apply if a contract is re-filed for approval of an amendment that affects the contract price. This review process will be applied to contracts pending approval because we have limited AMFs and have several pending and soon-to-be-filed RPS contracts that will require AMFs.

55 Review standards for bilateral and short-term contracts will be addressed in R.06-02-012 or R.08-08-009, as appropriate

56 § 399.15(d)(4) allows the IOUs to voluntarily procure RPS contracts at above-market prices that are not counted toward the cost limitation.

57 CEERT proposes that we evaluate prices based on MPR + REC. This is not consistent with Commission review of other RPS contracts, nor consistent with our understanding of how bundled contracts are priced.

58 As CalWEA points out in their comments on Draft Resolution E-4199, and as the RETI Phase IB Report discusses (Summary Section 1.5), there is uncertainty associated with the RETI data. A number of assumptions are used in the modeling, and the results represent the costs of developing a project at one point in time. While the RETI data can be used as a data point in the price reasonableness assessment, staff should recognize that there are project-specific factors that affect a contract's negotiated price.

59 D.06-05-039 requires IE reports for RPS contracts

60 DRA, SDG&E and TURN support the use of cash flow models. PG&E, SCE and CalWEA/LSA disagree.

61 If other amendments are filed that affect the contract price, Energy Division staff have the discretion to ask for cash flow model, but we will not require it. Also, due to the highly sensitive information contained in cash flow models, the IOUs and developers can work with the Commission to use non-disclosure agreements (NDA), if desired. The Commission has already drafted an NDA that an IE and developer found acceptable, though we do not reproduce it in this resolution because of certain project-specific information.

62 To keep contract review and approval consistent, IOUs must include this information in advice letters or applications for all RPS contracts, whether the IOU thinks the contract is or is not eligible for AMFs.

63 The AMF Calculator is not designed to cumulate the AMFs request for contracts with multiple phases that each have different online dates, even though all phases will be reviewed at the same time by the Commission and count cumulatively towards the same AMFs request. As a result, separate AMFs Calculators should be completed and submitted for each phase.

64 http://www.cpuc.ca.gov/PUC/energy/Renewables/index.htm

65 As explained in Section 3.2 above, we adopt the IOU's cost limitations in 2008$ (nominal dollars).

66 Draft Resolution E-4160, p. 15

67 SCE provided a sample calculation in Appendix B to their pre-workshop comments. (SCE pre-workshop comments, May 7, 2008)

68 A few changes have been made to the proposed Calculator to reflect the decisions in this resolution, remove the IOUs' notes, and to match the extension of the MPR to 25 years.

69 AMFs Calculator, AMFs Summary tab, Cell C5.

70 AMFs Calculator, AMFs Summary tab, Cell C3

71 AMFs Calculator, AMFs Summary tab, Cell C7

72 Both the contract price and MPR are also adjusted by the utility's time of delivery factors.

73 One must also know the contract term length, however we will not discuss it because the duration of the contract is certain.

74 An accurate COD is also needed for the AMFs calculation to reflect the start date of payments; using an inaccurate start date in the Calculator would lead to an inaccurate calculation of the total amount of AMFs needed.

75 Each utility submits its utility-specific TOD factors with its annual RPS Procurement Plan. They determine TOD factors based on its analysis of the forward value of energy and capacity during different times of day and times of the year. This results, in practice, in each utility valuing electricity at different hours differently, sometimes significantly so. As relevant to the MPR calculation, the three large utilities use between six and nine TOD periods.

76 See Resolution E-4183 (July 31, 2008), p. 14

77 To keep contract review and approval consistent, IOUs must include this information in advice letters or applications for all RPS contracts, whether the IOU thinks the contract is or is not eligible for AMFs.

78 Pursuant to the Commission's confidentiality rules, the IOU can request confidential treatment for information contained in the Matrix in D.06-06-066, but information not protected must be included in the public version of the advice letter.

79 CEERT says, "For AMF-eligible RPS-contracts, the utility has the discretion to determine whether those funds will be applied to cover the cost of the REC (in the reasonableness review equation of MPR + REC) or to apply the AMF to costs incurred above the reasonableness review standard of MPR + REC." (Post-workshop comments, July 8, 2008,p. 12)

80 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.

81 "The above-market costs of a contract selected by an electrical corporation may be counted toward the cost limitation if all of the following conditions are satisfied..."

82 DRA's argument reflects their desire to adopt rules that out-of-state RPS contracts can not receive AMFs.

83 D.06-05-039 requires each IOU "to provide us with information on whether each approved RPS project... is on target with the project's milestones and projected initial operation date." This information must be provided with each compliance report (currently due March 1 and August 1 of each year; see D.05-07-039, Ordering Paragraph 17)." (D.06-05-039, p. 23)

84 D.06-06-066, p. 59

85 This is consistent with § 399.15(d)(4), which allows IOUs to enter into and seek Commission approval for RPS contracts that have contract prices above the MPR even if the IOUs AMFs cost limitation has been reached.

86 Parties were asked to comment on what amendments are within the scope of contract administration in the Amended Scoping Memo and Ruling of Assigned Commissioner Regarding 2009 RPS Procurement Plans (June 20, 2008).

87 This change must then be incorporated into the next PDSR. The service lists will not be updated of the IOU's AMFs balance until after the PDSRs are reviewed.

88 The Director will also send a letter stating what the IOUs baseline AMF balances are after the IOU's submit their `current AMF Calculator' shortly after this Resolution is approved .

89 in either an advice letter filing or in the PDSR

90 We do encourage IOUs to negotiate terms that identify project milestones and have consequences if developers do not meet deadlines.

91 CEERT comments on Draft Resolution E-4199, February, 5, 2009, p. 3

92 CEERT's post-workshop comments, July 8, 2008, p. 6

93 SCE comments on Draft Resolution E-4199, February, 5, 2009, p. 1

94 SCE comments on Draft Resolution E-4199, February, 5, 2009, p. 2

95 http://docs.cpuc.ca.gov/efile/RULINGS/96981.pdf

96 SCE comments on Draft Resolution E-4199, February 5, 2009, p. 2

97 ACR Regarding Potential RPS Development in Imperial Valley and Evaluation of Renewable Procurement Contracts, Attachment B p. 5

98 PG&E comments on Draft Resolution E-4199, February 5, 2009, p. 3

99 PG&E comments on Draft Resolution E-4199, February 5, 2009, p. 3

100 The model associated with the contract price already approved by the Commission

101 D.06-06-066, p. 3

102 DRA comments to Draft Resolution E-4199, February 5, 2009, p. 4

103 DRA comments on Draft Resolution E-4199, February 5, 2009, p. 5

104 DRA comments on Draft Resolution E-4199, February 5, 2009, p. 7

105 PG&E comments on Draft Resolution E-4199, February 5, 2009, p. 3

106 CEERT also asserts that the Draft Resolution mischaracterized CEERT's position on RPS reasonableness review. The discussion in this Resolution has been modified appropriately.

107 PG&E Reply comments, February 10, 2009, p. 2

108 CEERT comments on Draft Resolution E-4199, February 5, 2009, p. 5

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