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Order Instituting Rulemaking to Integrate and Refine Procurement Policies and Consider Long-Term Procurement Plans.

Rulemaking 10-05-006

(Filed May 6, 2010)

(1) Track I will identify California Public Utilities Commission (CPUC)-jurisdictional needs for new resources to meet system or local resource adequacy and to consider authorization of IOU [investor-owned utility] procurement to meet that need...

(2) Track II will address the development and approval of individual IOU "bundled" procurement plans consistent with § 454.5.

(3) Track III will consider rule and policy changes related to the procurement process which were not resolved in [Rulemaking] R.08-02-007, as outlined in greater detail below. (OIR at 9.)1

1) [P]rocurement rules relating to once-through cooling issues; 2) refinements to the bid evaluation process, particular weighing competing bids between utility-owned generation and power purchase agreements; 3) refinements to the existing timelines associated with the utilities' RFOs [requests for offers] for resource adequacy products; and 4) utility procurement of greenhouse gas related products. (March 10, 2011 ALJ Ruling at 4.)

As a compromise among their respective litigation positions, and subject to the recitals and reservations set forth in this Settlement Agreement, the Settling Parties agree that:

· With respect to system resource need and the integration of intermittent renewable resources into the CAISO grid, the Settling Parties encourage the Commission, in conjunction with the CAISO's ongoing work on this subject, to further examine this issue expeditiously in the next Long-Term Procurement Plan (LTPP) cycle or in an extension of the current LTPP cycle.

· All references to a potential "need to add capacity for renewable integration purposes" shall be interpreted within the context of the CAISO process which considers alternatives as further described in Section III.C below to determine the type of resources (including existing units) available to meet any defined needs. There is no presumption that any Phase 1 "need" requires the addition of new gas-fired generation resources above and beyond those needed to meet the current planning reserve margin.

· As requested by the Commission, the CAISO developed a methodology for assessing renewable integration resource needs (the "CAISO methodology"), and applied this methodology with the assistance of the IOUs to assess the need for flexible capacity for the four CPUC-Required Scenarios and one other CPUC scenario analyzed by the CAISO. The results show no need to add capacity for renewable integration purposes above the capacity available in the four scenarios for the planning period addressed in this LTPP cycle (2012-2020). The additional scenario studied by the CAISO did show need.

· The IOUs applied the same CAISO methodology for the IOU Common Scenarios using different assumptions from those used in the CPUC-Required Scenarios. The results of the IOUs' modeling show need for additional capacity for renewable integration purposes under certain circumstances.

· The resource planning analyses presented in this proceeding do not conclusively demonstrate whether or not there is need to add capacity for renewable integration purposes through the year 2020, the period to be addressed during the current LTPP cycle. The Settling Parties have differing views on the input assumptions used in, and conclusions to be drawn from the modeling. There is general agreement that further analysis is needed before any renewable integration resource need determination is made. [...] (Settlement Agreement at 4-5.)

TURN has been monitoring the development of the CAISO methodology for assessing renewable integration resource needs and believes that the model cannot be relied upon to authorize any additional procurement at this time. (The Utility Reform Network (TURN) Opening Brief at 1.)

In the opinion of the GPI, the overwhelming conclusion of the analyses presented in Testimony by the CAISO and the utilities is that it makes little difference which renewables development trajectory is followed. The costs are all about the same, the environmental improvements are all about the same, and despite the fact that promising new technologies for improving grid operations are left out of the analysis, there is still no identified need for new fossil-fired resources for purposes of renewables integration in any of the PUC-defined scenarios. (Green Power Opening Brief at 15-16.)

Regarding Track I, CBE is a party to the settlement agreement submitted on August 3, 2011. CBE recommends the Commission approve the proposed settlement. In so doing, CBE requests that the Commission specifically find that the evidence presented in this proceeding does not establish a need for new generation to integrate renewables. CBE further requests that the Commission specifically find that neither Pacific Gas and Electric ("PG&E) nor Southern California Edison ("SCE") have requested or established a need for new generation to meet local area need. (Communities for a Better Environment (CBE) Opening Brief at 2.)

[E]ven if system-wide studies do not identify a need for additional resources on a statewide basis, there may nevertheless still be a need for new resources to meet local resource adequacy criteria. (Id. at 5.)

Current and expected wholesale market conditions do not provide uncontracted existing generation resources with reasonable opportunities to secure sufficient and stable revenue streams to recover going forward costs, including maintenance necessary to ensure availability in the future. As a result, if a procurement mechanism is not adopted in the near term to address this situation, economic retirements should be expected. (Calpine Opening Brief at 3.)

Q So you don't know whether there are any other uncontracted combined cycle units outside of Calpine's fleet?

A I strongly suspect there are, but I don't know that for a fact. (Calpine witness Barmack, Transcript vol. 6 at 865-866.)

Q Dr. Barmack, what units other than the Calpine units do you believe are at risk of shutting down?

A It would be purely speculation on my part, but I'm aware of other combined cycles that were built around the same time as many of our units... I'm not aware of whether those units are contracted or not. (Id. at 888.)

Q So Calpine hasn't provided any information about the cost of operating the existing units in its combined cycle fleet to the Commission in this proceeding, has it?

A No. We haven't provided information about the specific economics of our units. (Id. at 851.)

During cross-examination, Calpine witness Barmack acknowledged that there are significant regulatory limitations on Calpine's ability to retire a power plant. As Dr. Barmack acknowledged, under the Commission's General Order ("GO") 167, Calpine is obligated to maintain its generating units in California in readiness for service unless the Commission, after consultation with the CAISO, affirmatively declares that the units are unneeded during a specified period of time. Moreover, under GO 167, Calpine is obligated to notify the Commission and the CAISO in writing at least 90 day in advance of any planned change in the long term status of any Calpine unit in California. Under the CAISO's tariff, the CAISO has the authority to issue a "risk of retirement" designation to keep a resource in operation that is otherwise at risk of retirement during the current "resource adequacy" year if the CAISO believes the resource will be needed for reliability by the end of the following calendar year. Thus, a number of regulatory protections are in place to assure that Calpine's units, if needed for reliability in California, will remain on-line and operational. (PG&E Opening Brief at 13-14.)

Even if the short-term operating economics are unfavorable, Woodruff explains that Calpine has a variety of options including asset sales or temporary shutdown. The notion that Calpine would physically dismantle these units, which is the basis of their request, is simply not credible. (Id. at 5.)

The Policy establishes technology-based standards to implement federal Clean Water Act section 316(b) and reduce the harmful effects associated with cooling water intake structures on marine and estuarine life. The Policy applies to the 19 existing power plants (including two nuclear plants) that currently have the ability to withdraw over 15 billion gallons per day from the State's coastal and estuarine waters using a single-pass system, also known as once-through cooling (OTC). Closed-cycle wet cooling has been selected as Best Technology Available (BTA). Permittees must either reduce intake flow and velocity (Track 1) or reduce impacts to aquatic life comparably by other means (Track 2). (from SWRCB website, accessed on November 30, 2011: http://www.swrcb.ca.gov/water_issues/programs/ocean/cwa316/policy.shtml).

Power plant owners/operators can choose how they plan to comply with the Policy's required 93 percent reduction in their use of seawater. Two plants have ceased operation. Most have informed the State Water Board that they are planning to modernize their plants' equipment and will switch to air cooling systems. Some have chosen to use evaporative cooling towers. Others are pursuing alternative controls, such as screening. (SWRCB Fact Sheet at: http://www.swrcb.ca.gov/publications_forms/publications/factsheets/docs/oncethroughcooling0811.pdf, accessed on November 30, 2011.)

AES Southland purchased three gas-fired generation facilities from Southern California Edison (SCE) in May 1998: AES Huntington Beach, AES Redondo Beach, and AES Alamitos. (Ex. 1701 at 2 (AES, Didlo).) These three facilities supply 4,140 megawatts of local capacity within the transmission-constrained Western sub-area of the LA Basin Local Capacity Area (LCA). (Id.) These generating resources represent 50% of the total net qualifying capacity in the Western sub-area (Id. at 3), and were initially built by SCE as part of an integrated urban power delivery system. The concurrent planning of generation stations and transmission lines to minimize urban transmission requirements has created a high level of local dependence on these facilities that effectively utilize the transmission grid to satisfy system reliability. (Id. at 5, 6.)

Each of the facilities employs once-through cooling (OTC) technology. These facilities are thus subject to the Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling (OTC Policy) adopted by the California State Water Resources Control.

Board, and are currently required to comply with the OTC Policy by December 31, 2020. (Id. at 1-2). In order to comply with the OTC Policy, AES Southland intends to redevelop its locations by retiring the current operating units and replacing them with state-of-the-art gas turbine technology. (AES Southland Opening Brief at 1-2.)

Staff's proposal to limit the utilities' contracts with OTC facilities to a one-year period is a reasonable attempt to align procurement planning with California's policy of retiring OTC units. Instituting this relatively minor restriction on the duration of OTC contracts is a practical step toward California's goal of OTC phase-out, as set forth in the Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling ("Statewide OTC Policy") adopted by the California State Water Resources Control Board in October of 2010.

The Statewide OTC policy directs owners and operators of OTC facilities to comply with one of two compliance alternatives "as soon as possible, but not later than" their respective compliance dates. Staff's Proposal places workable restrictions on long-term OTC contracting to further the Statewide OTC Policy's of phasing out or repowering OTC units "as soon as possible." No party in this proceeding disputes the propriety of the Statewide OTC Policy or its compliance deadlines. Moreover, most of California's OTC units are aging, inefficient, and unreliable.

Staff's proposal is consistent with the Commission's policy of encouraging the protection of California's water resources. A one-year limit would incentivize and encourage a transition away from aging OTC resources "as soon as possible," consistent with the Statewide OTC Policy. Likewise, the one-year limit will deter utilities from waiting until near the end of the compliance period and subsequently asking for an extension of the shutdown date. (Pacific Environment Opening Brief at 30-31, footnotes omitted.)

[S]uch artificial restrictions on contracting opportunities would potentially harm the Commission's resource adequacy program, potentially harm system reliability, as well as increase costs to California ratepayers. This proposal is both untimely and unnecessary.

First, there is no reason to limit contracting opportunities for OTC plants prior to the compliance dates established by the SWRCB. Many, if not all, of the compliance dates established by the SWRCB are several years in the future. The one-year limitation on contracting thus serves no useful purpose, because it does not change the dates by which OTC units must comply with SWRCB rules. Further, the phased implementation of the SWRCB's new rules was carefully designed to provide generators time to comply with new rules, while ensuring that the State's environmental goals were accomplished. Adopting the Staff Proposal would upset this careful balance.

Second, limiting the ability of LSEs [load-serving entities] to contract with OTC units is likely to increase the prices such LSEs pay for generating capacity. LSEs routinely enter into multi-year arrangements in order to protect ratepayers against price volatility. Generators also benefit, because these longer term contracts limit their risk, thus promoting lower overall prices. The Staff Proposal, however, would increase prices by increasing the risk to generators, effectively encouraging them to seek higher prices in one-year agreements than they might accept for multi-year agreements. The Proposal would similarly artificially decrease the pool of potential long-term counterparties for LSEs to contract with, thereby making it more difficult for the LSEs to meet their long-term needs on a least-cost basis. The Staff Proposal would thus increase the price LSEs pay for generation while providing little or no environmental benefit.

Third, lack of access to longer-term contracts may lead to decreased system reliability, because longer-term contracts allow for longer-term system planning. There is no question that limiting access to longer-term contracts would increase the uncertainty of future revenue streams for existing OTC generators seeking to comply with the OTC Policy under either Track 1 (replacement by a non-once-through-cooled generation) or Track 2 (mitigation of impingement and entrainment impacts). This uncertainty will manifest itself in higher prices (as discussed above) and also make it difficult for existing units to plan their capital expenditure spending in order to comply with OTC and other environmental rules. (NRG Opening Brief at 2-3.)

... SDG&E does not oppose the proposal to limit the IOUs' ability to enter into contracts that would require operation of an OTC facility beyond the compliance date...(SDG&E Opening Brief at 22.)

Similarly, DRA stated that:

Therefore, DRA recommends that the rule be that utilities may not enter into contracts with any OTC facility that would extend beyond the final date the facility is scheduled to retire or repower under the SWRCB policy statement. If a counter-party can demonstrate that the OTC facility will continue to operate and be in compliance with SWRCB requirements after its compliance deadline, this restriction should not apply. (DRA Opening Brief at 26.)

CLECA pointed out that the problem is not the length of the contracts. [citation omitted] It is how to prepare for the retirement or repowering of these units in the context of making cost-effective decisions to address local reliability needs given the SWRCB regulations. CLECA notes that the Settlement in Track 1 of this proceeding provides a plan to assess these local reliability needs over the next year. The Commission should consider the results of that assessment before reaching any decision on contracting for the output of fossil OTC units. (CLECA Opening Brief at 5-6.)

Rather than limiting contracts with OTC units to one year, the Commission should focus its OTC policy consideration on examining the need for replacement capacity, as discussed below. Indeed, it may be the award of a multi-year contract that provides the financial underpinnings that will enable an OTC unit to invest in an upgrade of its cooling facilities to become compliant with the OTC regulations, or perhaps undertake an even more extensive repowering.


The CAISO is engaged in studies to assess the impact of OTC retirements consistent with the SWRCB's policy. WPTF recommends that the Commission should await the final results from the studies before making any determinations as to the need for replacement capacity associated with OTC retirements. (WPTF Opening Brief at 5.)

Finally, in light of the further needs analysis contemplated by the Settlement Agreement, and the CAISO's focus on evaluating how OTC compliance deadlines affect the need for new capacity to meet LCR, the Commission should allow parties to make policy recommendations regarding the replacement of OTC facilities in the next phase of this proceeding. It is difficult to make cogent recommendations regarding what types of procurement policies are needed to support OTC goals until the CAISO' s additional study results are known. As the understanding of the impacts of OTC retirements becomes more complete, policy choices that are not readily apparent today may become more apparent then. (GenOn Opening Brief at 2-3.)

Exhibit 211, at pp. 4-9, describes SCE's proposal that the Commission open a new proceeding to address a new generation procurement method for new capacity for replacement of OTC generation or meet renewable integration needs required to maintain reliability of the electric grid in the future. SCE proposed a "CAISO new generation auction to commence the debate on the appropriate mechanism to meet the new generation need." (SCE Opening Brief at 14.)

There are very real problems associated with evaluating UOG proposals in competition with PPA bids. The uneven life cycles of PPA contract periods (traditionally ten years) are shorter than the life of a UOG asset, which inevitably tilts any discounted cash flow analysis in favor of the longer lived UOG assets. PPAs and UOG also have very different risk profiles, with UOG having assurance of ratepayer cost recovery while PPA project sponsors must factor a return into their bids. And of course, UOG projects enhance utility profits through additions to rate base, whereas PPAs do not. An RFO that requires comparisons of UOG versus PPA projects is neither credible nor manageable. Finally, and of equal importance, having the IOUs in a position to evaluate their own UOG projects in comparison to PPA bids creates a very real perception of bias that in turn compromises the competitiveness of the RFO. (WPTF Opening Brief at 6.)

[T]he Commission should bar utilities from imposing arbitrary or discriminatory limits on the contract term that IPPs can propose. If a UOG is evaluated on the basis of its 30-year useful life, IPPs should be allowed to propose PPAs with terms of up to 30 years. If IPP PPAs are limited to 10 years, then UOG projects should be evaluated as if cost recovery is limited to 10 years. (Id.)

DRA recommends that the Commission provide specific guidance to the IOUs on what input assumptions or forward cost curves are reasonable to use for UOG valuations. This guidance should be developed and vetted through a public stakeholder process held at the Commission. This guidance will help to level the playing field for comparing UOG and PPA bids. (DRA Opening Brief at 33.)

The costs of developing a specific UOG project are included in the cost estimate for the project, and will be part of the project costs which the Commission considers in the CPCN and reasonableness review processes for UOG. (SCE Opening Brief at 24-25.)

The Commission should require that the critical cost parameters of any UOG bid should be binding on the IOU for the first ten years of project operations. "Critical cost parameters" include initial capital costs, capital additions, fixed and variable O&M, and heat rates. TURN witness Woodruff explains that this requirement is appropriate because of "the potential for the costs of UOG resources to escalate from those upon which the evaluation and selection was based." Given the typical treatment for UOG resources, in which IOUs are not held to forecasts of cost or performance after the project achieves initial commercial operation, the Commission must take action to create real accountability so the original selection process is not unfairly biased in favor of UOG.

Absent this type of accountability, IOUs have an incentive to assume superior long term cost and performance advantages of UOG projects. Since the Commission rarely, if ever, revisits these initial assumptions, there is no penalty to making overly optimistic projections that are never realized. Even if they are revisited, the IOU need only demonstrate that the costs are reasonable at the time they are incurred. The absence of any accountability mechanism only emboldens IOUs to game this process to the benefit of shareholders and the detriment of ratepayers.

TURN encourages the Commission to adopt this general principle in this proceeding and leave the details to any utility-specific application seeking approval of a UOG project. (TURN Opening Brief at 7-8.)

[T]hat the Commission establish hard cost caps for capital costs and Operation & Maintenance (O&M) for UOG projects, so that the IOUs will not underbid these costs and then attempt to recover higher costs after the UOG project has been approved. (DRA Opening Brief at 33.)

DRA points out that UOG can be compared with IPP PPAs, but recommends certain modifications to the bid evaluation process. Most notably, DRA proposes that in approving UOG projects, the Commission should cap recovery of capital costs and operations & maintenance ("O&M") costs at the level included in the UOG bid. In general, SDG&E does not object to the proposal to cap recovery of capital costs, provided that the IOUs have the right to file an Application to recover additional costs in the event capital costs exceed the amount included in the UOG bid. This approach is fair and is analogous with Commission treatment of IPP requests to re-price PPAs. With regard to O&M costs, however, DRA's proposal is not workable.

Under SDG&E's GRC [General Rate Case] cost recovery methodology, ratepayer risk is capped on an aggregate basis rather than a project-specific basis. The O&M revenue requirement, for example, is expressed as a total amount that covers all O&M costs - an O&M cost on one project that is below what was forecasted may offset a cost overrun on a different project. If aggregate costs exceed the O&M revenue requirement, shareholders are at risk for the excess O&M amount. Thus, because the GRC cost recovery methodology does not contemplate project-specific O&M price caps, the Commission should not adopt DRA's O&M cost cap proposal. (SDG&E Reply Brief at 32-33, footnotes omitted.)

UOG offers shall not be considered in RFOs. Rather, utility-owned projects shall be proposed to the Commission via traditional applications for a certificate of public convenience and necessity only when and if a competitive solicitation has failed. (Id.)

Under the current rules, the utility will have already have to show that a competitive process was not feasible or appropriate in its application, and the Commission can then determine whether the utility's case is compelling. (Id.)

CARB's cap-and-trade program authorizes IOUs to meet a portion of their greenhouse gas compliance obligation through the purchase of offsets that comport with CARB's previously-approved offset protocols. [fn. omitted] Offsets will only be certified as compliant after the fact, that is, once the GHG emission reduction has taken place and has been verified. Once an offset is certified, it can be used to fulfill a compliance obligation. However, unlike an allowance, a CARB-certified offset may have its CARB certification revoked. This revocation can occur even after the offset was accepted by CARB for a compliance obligation, if it was later found to have been certified erroneously, under false pretenses, or if the project from which the offset was derived did not meet CARB's permanence requirement. (SCE Ex. 210 at 6.)

By reducing the cost of compliance, offsets have environmental impacts by making emission reduction projects at capped IOU sources less desirable. Every ton of offsets claimed is a ton of emission reductions that IOUs do not have to achieve. There will be less incentive to explore alternatives that reduce demand (e.g., energy efficiency, demand response) or reduce emissions (e.g., increased renewable generation or repowering or replacement of inefficient generators). (Sierra Club Opening Brief at 12.)

The action for which the IOUs seek approval constitutes a "project" because it would allow the IOUs to engage in an activity that may cause a direct or reasonably foreseeable indirect physical change to the environment. Offsets in the AB 32 cap and trade program not only impact the environment by allowing covered sources to avoid making greenhouse gas emission reductions, but they represent projects that themselves can have environmental impacts. Currently, CARB has identified four categories of projects that can generate offsets: livestock manure (digester) projects; urban forest projects; ozone depleting substances projects; and U.S. forest projects. See, e.g., Ex. 313 at 7. These offset projects will undeniably effect the environment in ways that are different than reducing emissions from capped sources. The two forestry offset options do not involve controlling emissions at all, but instead give credit to the creation of emission "sinks" that have the potential to absorb the increased greenhouse gas emissions that would be allowed. See CARB, "Functional Equivalent Document Prepared for the California Cap and Trade Regulation," Appendix O, at 271-337 (Oct. 28, 2010) (available at: http://www.arb.ca.gov/regact/2010/capandtrade10/capv5appo.pdf). It is also beyond dispute that the environmental impacts of reducing emissions from livestock manure operations will be different than the impacts of reducing emissions at capped IOU sources. Id. at 235-270. Cross-examination of IOU experts affirmed the differing environmental impacts of reducing capped emissions and using offsets instead. See, e.g., Cross-Examination of Mr. Miller, SDG&E, Trans. at 805 (agreeing that "[i]t would make sense" that the environmental impacts would be different). (Sierra Club Opening Brief at 16, emphasis added.)

Thus, there is more than a fair argument that the approval of offsets will have significant environmental impacts. [citation omitted] As such, an environmental analysis of the proposed action as well as consideration of alternatives and mitigation measures must be prepared before making any decisions. (Sierra Club Opening Brief at 18.)

"Tiering" refers to using the analysis of general matters contained in a broader EIR (such as one prepared for a general plan or policy statement) with later EIRs and negative declarations on narrower projects; incorporating by reference the general discussions from the broader EIR; and concentrating the later EIR or negative declaration solely on the issues specific to the later project. (CEQA Guideline 15152(a).)

(d) Where an EIR has been prepared and certified for a program, plan, policy, or ordinance consistent with the requirements of this section, any lead agency for a later project pursuant to or consistent with the program, plan, policy, or ordinance should limit the EIR or negative declaration on the later project to effects which:

(1) Were not examined as significant effects on the environment in the prior EIR; or

(2) Are susceptible to substantial reduction or avoidance by the choice of specific revisions in the project, by the imposition of conditions, or other means. (CEQA Guideline 15152 (d).)

[D]etermination of the treatment of GHG compliance costs associated with contracts executed between independent generators and utilities prior to the passage of AB 32 that do not include a mechanism for recovery of such costs. (IEP Motion at 3.)

The Commission currently requires each IOU to submit a Quarterly Compliance Report (QCR) via the Commission's advice letter process within 30 days of the end of every calendar quarter, in order for Commission Staff to review the IOU's procurement transactions for compliance with the Commission-approved procurement plan and its up-front and achievable standards and criteria. (Id. at 185.)

PG&E recommends that if this proposal is adopted, the Staff report include both the audit findings and the IOU response to those findings in a single document. (PG&E Opening Brief at 34.)

If there are any audit observations or discrepancies that cannot be resolved between the audit staff and the utility, the utility may submit a rebuttal that is incorporated into the final audit report, and which may also include the utility's original general comments. (SCE Opening Brief at 34.)

While SDG&E does not oppose making QCR audit reports public, it recommends that the Energy Division be required to include in the body of the QCR audit report the IOU's comments in response to the findings set forth in such audit report - this should be required in all instances, not merely when discrepancies exist. (SDG&E Opening Brief at 40-41.)

This is sufficient time for PRG members to review the summaries in advance of the meeting, but also allows the flexibility for the development of meeting summaries if PRG meetings are close in time or involve more complicated summaries that require sufficient time to prepare. (PG&E Opening Brief at 34.)

New IE report filing requirement: For solicitations of products five years or greater in length, the IE report shall be filed with Energy Division and the PRG at least 7 calendar days before any IOU application is filed with the CPUC and the IE report should also be submitted as an attachment to the application. (June 13, 2011 Ruling, Appendix B.)

c. PG&E, SCE, and SDG&E contracts with facilities utilizing once-through cooling may extend beyond the State Water Resources Control Board once-through cooling compliance date, but only if such contracts: 1) Allow for utility purchase or receipt of power generated by a unit using non-compliant once-through cooling only up to the State Water Resources Control Board once-through cooling policy compliance date in effect on the date the contract is signed. The contract shall not allow PG&E, SCE, and SDG&E to continue to purchase or receive power generated using non-compliant once-through cooling beyond that date even if the State Water Resources Control Board extends the compliance date; 2) Protect utility ratepayers against stranded costs; 3) Protect ratepayers against the risk of future unspecified cost increases resulting from increases in the cost of the generation unit compliance with the State Water Resources Control Board once-through cooling policy. For a utility to recover such cost increases from ratepayers, it must obtain approval from the Commission; 4) Are consistent with a need authorization from the System Track of the Long-Term Procurement Plan proceeding; and 5) Are consistent with other procurement rules, including this decision's requirement to file either a Tier 3 Advice Letter or an application.

b. PG&E, SCE, and SDG&E may only procure offsets certified by the California Air Resources Board.

c. PG&E, SCE, and SDG&E may purchase no more than 8% of their compliance requirement in the form of offsets.

d. PG&E, SCE, and SDG&E can only purchase offsets if the seller contractually assumes the risk of invalidation.

e. PG&E, SCE, and SDG&E may procure allowances from the California Air Resources Board.

f. PG&E, SCE, and SDG&E may procure allowances via forward contracts, and should apply their standard procurement credit and collateral requirements to these transactions, and may also impose additional credit and collateral requirements as appropriate.

g. If PG&E, SCE, and SDG&E wish to procure authorized compliance instruments via bilateral transactions (including brokers), PG&E, SCE, and SDG&E must utilize a competitive request for offer process, consult with their procurement review group, apply their approved procurement credit and collateral requirements, and apply the applicable affiliate transaction rules.

h. PG&E, SCE, and SDG&E may procure greenhouse gas compliance instruments on Commission-approved exchanges. Prior to purchasing greenhouse gas compliance instruments on an exchange not previously approved by the Commission for power procurement, PG&E, SCE, and SDG&E must submit a one-time Tier 2 advice letter detailing: 1) what exchange they are seeking to use; 2) the liquidity and transparency of the exchange, specifically for California greenhouse gas compliance instruments, including an explanation of how the Commission can be assured that the price of products procured on the exchange is reasonable; and 3) the regulatory authority or authorities the exchange is subject to.

i. PG&E, SCE, and SDG&E may resell greenhouse gas compliance instruments, but should report any such sales to their procurement review group.

1 These tracks are referred to as System Track I, Bundled Track II, and Rules Track III.

2 The full title of the Ruling is: Administrative Law Judge's Ruling Modifying System Track I Schedule and Setting Prehearing Conference.

3 Administrative Law Judge's Ruling Revising System Track I Schedule, dated March 10, 2011.

4 Administrative Law Judge's Ruling Granting Motion to Modify System Track I Schedule, dated May 31, 2011.

5 Administrative Law Judge's Ruling Addressing Motion for Reconsideration, Motion Regarding Track I Schedule, and Rules Track III Issues, dated June 13, 2011.

6 Consistent with the Administrative Law Judge's Ruling Addressing Motion for Reconsideration, Motion Regarding Track I Schedule, and Rules Track III Issues, dated June 13, 2011, additional reply testimony was presented on August 11, 2011.

7 Motion For Expedited Suspension Of Track 1 Schedule, And For Approval Of Settlement Agreement Between And Among Pacific Gas And Electric Company, Southern California Edison Company, San Diego Gas & Electric Company, The Division Of Ratepayer Advocates, The Utility Reform Network, Green Power Institute, California Large Energy Consumers Association, The California Independent System Operator, The California Wind Energy Association, The California Cogeneration Council, The Sierra Club, Communities For A Better Environment, Pacific Environment, Cogeneration Association Of California, Energy Producers And Users Coalition, Calpine Corporation, Jack Ellis, Genon California North LLC, The Center For Energy Efficiency And Renewable Technologies, The Natural Resource Defense Council, NRG Energy, Inc., The Vote Solar Initiative, And The Western Power Trading Forum.

8 Rule 12.1(d) states: "The Commission will not approve settlements, whether contested or uncontested, unless the stipulation or settlement is reasonable in light of the whole record, consistent with law, and in the public interest."

9 While the focus of this proceeding extends out to 2020, it is important to note that the record similarly does not support a finding of need for additional generation beyond 2020. Accordingly, it is also reasonable to defer procurement of generation for any estimated need after 2020.

10 We note that Calpine filed a notice with the Commission under GO 167 on 11/22/11, stating that it intended to retire its Sutter Energy Center generation plant in 2012. Draft Resolution E-4471 orders Calpine not to retire the Sutter plant. http://docs.cpuc.ca.gov/word_pdf/COMMENT_RESOLUTION/157581.pdf.

11 Administrative Law Judge's Ruling Revising System Track I Schedule, dated March 10, 2011.

12 Administrative Law Judge's Ruling Addressing Motion for Reconsideration, Motion Regarding Track I Schedule, and Rules Track III Issues, dated June 13, 2011.

13 Issues relating to UOG "proposed eligible renewable energy resources" are more appropriately addressed in the RPS Rulemaking, R.11-05-005.

14 SDG&E provides no citation for this issue.

15 This confusion is understandable, as the section heading appears to indicate that an advice letter would be required for each transaction.

16 Pursuant to its certified regulatory program, CARB prepared a "Functional Equivalent Document," (FED) as authorized by Pub. Resources Code section 21080.5.

17 Sierra Club is misapplying the criteria for evaluating alternatives in an Environmental Impact Report (EIR) under CEQA, where the lead agency will examine different approaches (CEQA Guideline 15126.6), to the threshold question of whether there is a significant impact on the environment (CEQA Guideline 15064).

18 In discussing forwards, we are considering them to be an obligation to deliver actual allowances, rather than a financial obligation. (Ex. 313 at 8.)

19 SCE makes legal and jurisdictional arguments that this Commission has no authority to even consider this issue. We note that the other parties have not had an opportunity to respond to these arguments. But even on the limited record before us on this issue, we do not believe that the legal issues are as clear-cut as SCE asserts.

20 The Commission may also choose to address this issue in this proceeding or a successor proceeding.

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