IX. Other Procurement Issues

A. Resource Adequacy Issues Not Addressed in the Resource Adequacy Decision

The RA decision, D.04-10-035, accelerated the target date to June 1, 2006, for the IOUs to acquire their reserve margins of 15-17% as established in D.04-01-050. Comments on the PD in the RA decision were circulating concurrently with the post-hearing briefs in the LTPP portion of this proceeding. Numerous parties raised the same issues in the post-hearing briefs as well as in their comments to the RA PD. In particular, parties weighed in on the creation of a multi-year forward commitment obligation. This topic is clearly specific to the RA decision since it is related to the design features of that program and it is appropriate to visit it in Phase II of RA.

Parties also raised the issue of the treatment of resource acquisitions over 17%. D.04-01-050 established the reserve margin requirement of 15-17%, and D.04-10-035 accelerates the due date, but does not change the 15-17%. Some parties interpret the RA range to mean that 15% is desirable and up to 17% can be acceptable temporarily due to lumpiness issues. Others view 16%, the average of 15-17%, as being the target. Still some parties argue that only acquisitions over 17% should raise any issue of penalties or disapproval. Since the RA phase is designed to handle the reserve margin issues we will not rewrite D.04-01-050 in this decision. If parties want further clarification on the interpretation of the 15-17% requirement they should bring it up in Phase II of the RA portion of this docket. This LTPP decision is not intended to change or modify any aspect of D.04-10-035. Any clarifications, alterations or augmentations to D.04-10-035 will be deferred to Phase II of the RA aspect and not addressed here.

B. Local Reliability as Part of the Procurement Process

D.04-07-028, issued in July 2004, established temporary local reliability requirements. Parties presented a full spectrum of viewpoints on this topic in their post-hearing briefs from deferring procurement until locational requirements are more fully defined, to wanting the IOUs to procure now.¹⁴⁶ While we expect RA Phase II to provide further guidance to the utilities in their procurement efforts to meet local reliability requirements, in the interim we extend the requirements of D.04-07-028. In particular, we underscore the direction provided in the July Order to procure and dispatch resources in a manner that considers real-time CAISO operational requirements and all known or reasonably anticipated CAISO related redispatch costs. We expect that the utilities will incorporate CAISO related must-offer, redispatch, and other related costs when undertaking procurement pursuant to the authority provided in this decision. SDG&E is a unique case among the three IOUs in that within service area resource additions almost certainly will provide local reliability benefits, unlike SCE or PG&E.¹⁴⁷ We therefore direct SDG&E to pursue the EAP loading order priorities when it makes resource additions.

C. Bottom-up Planning

Prior to the restructuring of the electric utility industry in California, the utilities were actively involved in integrated resource planning. With the passage of AB 1890 and the restructuring of the industry, the utilities moved away from active involvement in resource planning and became merchants of power on behalf of their customers. Since the California energy crisis, the pendulum has begun to swing back in the other direction again. The utilities are more actively involved in developing, as well as contracting for, the resources required to serve their customers. Naturally, this has led to renewed interest in making sure that the choices reflect the best trade-offs among the uses of society's limited resources.

In the January 2004 Policy Decision (D.04-01-050) we stated that by relying on a bottom-up approach to system planning, "[t]he Commission and utilities would be able to ensure that state policies are implemented in a manner designed to contain cost while achieving other goals. Such a process is not merely consistent with the state's broader policy goals - it will help sustain them."¹⁴⁸ That decision discussed integrated resource planning as a vehicle to provide a comprehensive context for all of a utility's resource decisions. The ACR/Scoping Memo in the current proceeding requested that the topic of bottom-up planning be included in the utilities' long-term plans.¹⁴⁹ All three utilities included discussions of bottom-up planning in their long-term plans as requested.

PG&E notes that it has followed the Commission's direction regarding planning, including following the EAP Loading Order, which was developed since the last long-term plans were filed. PG&E states that in its LTPP it has integrated the results of the CAISO-sponsored annual Assessment Studies and Electric Transmission Expansion Plan process into its integrated resource planning. The LTPP describes the processes underlying its adoption. PG&E will compare the most promising identified generation or demand response alternatives with the Commission-approved plan, and examine the planning level costs of all transmission, generation, and demand response alternatives. PG&E asserts that its account services representatives have historically looked at the individual needs of customers, practicing local planning at the lowest level, and will do so even more in the future as the utility acquires an increased portfolio of EE, DR, and DG resources.

SCE's LTPP described the annual planning process it uses to identify projects necessary to serve new load added to the utility's transmission and distribution system. SCE begins with development of 10-year peak-load forecasts for each substation in the SCE distribution system. These forecasts are developed using a bottom-up approach which takes advantage of the Company's regional engineers' knowledge of the local areas. Those substation-level forecasts are then compared to, and reconciled with, system demand forecasts developed using a top-down approach. Identification of system requirements requires technical studies performed as part of the load-growth planning process, which determines whether expected growth can be accommodated through the existing distribution system, or what kinds of projects are required to bring the system back to within specified loading limits. Development and evaluation of alternatives identifies alternatives for correcting any projected system deficiency. Finally, selection, approval and budgeting result in identification of the best combination of system performance, reliability, operational flexibility and cost to select a preferred plan from among the alternatives.

SDG&E states that because its entire service territory constitutes a single load pocket, the solutions offered for the service territory in total are identical to those envisioned by the Commission in its discussion of bottom-up planning. SDG&E has been an active participant in numerous regional planning and energy policy forums, as well as discussions with customers and other stakeholders, and has used any gained insights in its planning process. This approach includes, but is not limited to, working with the CSD to assist in meeting the goal of installing 50 MW of renewable resources by 2013 and finding ways to promote further development of, and explore possible future sites for, solar facilities in the San Diego region.

The three utilities have presented information on the processes they undertake to develop bottom-up forecasts of their needs and of the plans to deal with those needs. We are satisfied that the utilities are seriously following our direction and taking into account the needs of local areas within their service areas in developing their plans.

D. DWR contract allocation and reallocation (Sunrise)

The June 4, 2004, ACR/Scoping Memo provided the IOUs with conventions for DWR contract allocation and reallocation to be used in their modeling. The ACR asked the utilities to assume that the new DWR contracts, Kings River and CCS, be allocated to PG&E as proposed by DWR, and Sunrise allocation remain as is with SDG&E.

PG&E presented no DWR issue in this proceeding. SDG&E, although its position is that the DWR Sunrise contract should be reallocated to PG&E, conformed with the directions from the ACR and included Sunrise in its resource portfolio. SCE had no issue concerning DWR contracts for this proceeding.

There is another proceeding, A.00-11-035, that is addressing the subject of cost allocation of DWR contracts. Therefore, except for including DWR contracts in the utilities' resource portfolios, there is no DWR contract issue.

Therefore the arguments presented by SDG&E that keeping Sunrise in its plan reduces its option to address local reliability issues because Sunrise is outside the territory, provides no benefit to local reliability and leaves the utility with no "headroom" to add a local resource till the contract expires in 2010, and ORA's proposal that SCE contract with SDG&E for dispatch rights for specific units under the DWR-Williams contract, will be addressed either in the next phase of RA, or in the DWR contract proceeding.

DWR requests that this decision clearly state that nothing in this decision makes changes to prior Commission decisions, particularly D.02-12-074, the
IOU-DWR Servicing Agreements, or makes any changes in ratemaking treatment of the DWR contracts. We think DWR's request is reasonable and we adopt it until further Commission action on the subject.

E. Long-Term Planning in the Next Procurement Cycle

D.04-01-050 determined that in future cycles of the procurement process, we would link our timing to that of the CEC's IEPR. Since that proceeding operates on a biennial calendar, by stature, that means that the next long-term procurement proceeding will be in 2006. D.04-01-050 also linked the substance of the analyses we direct IOUs to file with the results of the CEC's IEPR information and analyses. In the past two years, the CEC and this Commission have been collaborating to a much greater degree than ever before, and as evidence the CEC is not a party to this proceeding and its staff is assisting our own staff in reviewing the IOU LTPPs and in developing resource adequacy procedures.

On September 16, 2004, President Peevey issued an ACR/Scoping Memo addressing further integration between the CEC's IEPR and our next procurement proceeding. That ACR suggested a specific type of coordination between the 2005 IEPR and the 2006 procurement proceeding. In essence, the CEC's IEPR would review IOU load forecasts, conduct a resource assessment and identify the range of need for new resource additions addressing significant uncertainties for each IOU. Our 2006 procurement proceeding would not relitigate those results, except in those cases where there is new information that was not available to be considered in the CEC's proceeding, and our 2006 procurement proceeding would address IOU resource procurement proposals and strategies in light of the range of need identified in the 2005 IEPR. We will also consider how CEC statewide policy recommendations may be translated into IOU-specific directives, given the circumstances of each IOU. A more specific enumeration of proposed relationships between this Commission, the CEC, and the CAISO is attached as Appendix B.

We endorse the coordination agreement and the direction to IOUs stated in the September 16, 2004 ACR. We direct IOUs to participate in the CEC IEPR proceeding as the one forum in which long-term load forecasts, resource assessments and need determinations will be considered. We believe Appendix B constitutes a good foundation for coordinated proceedings and the minimization of duplication between various planning proceedings. We direct our staff to work with the CEC and CAISO to effectuate this agreement in a complete and practical manner.

F. Utility filings demonstrating compliance

In prior Commission decisions issued in R.01-01-024, we established the following filing requirements:

Filing	Decision	Function
Monthly ERRA Report	D.02-12-074 (OP 19)	Shows the activity in the ERRA balancing account with copies of original source documents supporting each entry over $100.00 recorded in the account.
Monthly Portfolio Risk Report	D.03-12-062 (OP 2 and 4)	Informs the Energy Division on the risk exposure of the IOU's procurement portfolio.
Quarterly Transaction Report	D.02-10-062 (OP 8)	Tracks procurement transactions and shows that they comply with the approved procurement plan.
Semiannual ERRA Application	D.02-10-062 D.02-12-074 D.04-01-050	Sets electric energy procurement forecast rate. Enacts trigger, if met. Reviews contract administration and least-cost dispatch.
Short-Term Procurement Plan (STPP)	D.02-12-074 D.03-12-062	Addresses the procurement products, processes, risk management strategy and tools
Gas Supply Plan (GSP)	D.03-04-029 (OP 6)	Addresses how the IOUs plan to meet their natural gas needs regarding their electricity procurement functions
Long-Term Procurement Plan	D.04-01-050	Addresses how the IOUs plan to meet their electricity needs and incorporate Commission's directives in procurement planning

PG&E requests that the Commission streamline the review of procurement costs through quarterly transaction reports and ERRA proceedings. PG&E states that "by expediting the process for verifying that utility transactions are consistent with adopted procurement plans, the Commission can confirm that the utilities' procurement transactions are in compliance with an approved procurement plan and eliminate any second-guessing during subsequent ERRA compliance reviews... The Commission should require that the reviews be completed on time and the scope should be limited to review of the transaction identified by the independent auditor."¹⁵⁰

PG&E proposes the following: (1) Issue an omnibus resolution approving all unprotected, unresolved, quarterly procurement transaction advice letters as submitted, and (2) focus on truing up forecasted expenses to actuals in the ERRA compliance review proceeding and review the transactions identified in the quarterly transaction review process that are noncompliant with the procurement plan.

SDG&E recommends that the semiannual Gas Supply Plans be consolidated into the ERRA/STPP process, "as gas is an integral part of least-cost dispatch and short-term procurement planning and consolidation would eliminate redundancy, thus easing the resource constraints for both the Commission and SDG&E."¹⁵¹ Furthermore, SDG&E proposes that advice letter updates to the forecasts contained in the plan be filed in conjunction with each utility's ERRA forecast and that authorization would be for a rolling five years. SDG&E also recommends that gas supply plans be consolidated into the ERRA/STPP.

SCE suggests that the AB 57 plans need not be updated on an annual basis, and not in the ERRA proceeding. Instead, AB 57 can be updated as needed, e.g. if there were changes in the LTPP that required it.

DWR opposes SDG&E's recommendation that the Commission consolidate the review and approval of gas supply plans into the ERRA proceedings, stating that the recommendation is not consistent with the contractual obligations of SDG&E under its current Operating Agreement with DWR.

ORA recommends annual reviews of procurement plans in ERRA proceedings.

We continue the requirement for the Monthly ERRA Report and Monthly Portfolio Risk Report. In regards to the Quarterly Transaction Report, the IOUs are ordered to file a joint proposal to reformat the report in a way that will provide the Commission concise and coherent information, thereby streamlining the review process. The objective of the report is to show that the transactions entered into are in compliance with the upfront standards identified by the Commission. These reports will be reviewed by the ED staff. If there are no protests and the staff concludes that the transaction entered into in that quarter comply with the utility's procurement plan, then by the Commission's Expressed Delegation of Authority, the ED Director can approve the reports. However, if there are substantive protests and the staff takes issue with certain transactions, the staff will issue a draft resolution for the Commission's approval.

We find that no change is necessary at this time for the Semiannual ERRA Application. As for the STPPs, the 2006 LTPPs will contain the features of the Short-Term Plans that are not covered by the proposed 2004 LTPPs. That is, ultimately, we will eliminate the STPPs and the IOUs will act in accordance with a single Commission-approved plan. Until then, the existing STPPs will be in effect. Any updates to the existing STPP's should be filed with an AL 30 days after the issuance of this decision.

In regards to the semi-annual Gas Supply Plans and the biennial LTPPs, we find no change is necessary at this time.

G. Collateral Requirements

As part of its regular operation in a hybrid energy market, SCE periodically contracts with numerous counterparties for various electric and natural gas products. Counterparties require SCE to post collateral in the form of "cash or letters of credit if their exposure to SCE exceeds a predetermined negotiated limit (the Unsecured Credit Limit)." According to SCE's long-term plan:

"The requirement to provide collateral stems from a contracting counterparty's concerns that SCE will be unable to meet its obligations under the contract. These counterparties may be either physical buyers of SCE's excess energy or sellers of energy, capacity, or natural gas to SCE. SCE may also enter into financial transactions which act to hedge ratepayers' exposure to future market price movements.¹⁵² In each case, the transaction counterparties will attempt to minimize their risk by requiring SCE to post cash or letters of credit if their exposure to SCE exceeds a predetermined negotiated limit (the Unsecured Credit Limit)."¹⁵³

SCE states that its currently "authorized procurement plan includes sufficient collateral capacity for the near term. However, SCE's ability to stay within the current Commission authorized collateral limit will depend heavily upon the length of new contracts signed to meet resource needs."¹⁵⁴ SCE has stated its intent "to file an update to its STPP procurement plan within 30 days of the Commission's long-term procurement decision to conform it to Commission policies. If an increase to SCE's collateral capacity is required to carry out the revised plan, SCE will provide updated collateral estimates as part of this filing."¹⁵⁵ No party has taken issue with SCE on this issue. Accordingly, we accept SCE's stated approach.

We also note here that SCE can, and does, require counterparties to make similar collateral postings aimed at ensuring contract performance under changing market conditions. Calpine asks the "Commission [to] be sensitive to the fact that credit requirements can be used to either (i) squelch competition through onerous credit requirements; or (ii) to impose on ratepayers the costs associated with a zero risk tolerance."¹⁵⁶ Calpine warns that if "overcollateralized, project sponsors will be placed at a competitive disadvantage ... [and that these] excessive credit requirements will be passed on to ratepayers through higher prices."¹⁵⁷ (Id., p.19.) We are not aware of any specific claims of over-collateralization or associated recommendations.

H. New Accounting Rules

SCE has informed the Commission of two relatively new accounting rules promulgated by the Financial Accounting Standards Board (FASB) "that, like the debt equivalence issue, may affect electric utilities' costs of contracting for power."¹⁵⁸ One rule would require "utilities to include certain long-term contracts as liabilities on their balance sheets by deeming them capital leases,"¹⁵⁹ and the other rule (FASB interpretation) "could impose additional balance sheet impacts on utilities signing long-term contracts"¹⁶⁰

According to SCE, "a capital lease requires a utility to book the plant as an asset (similar to the accounting treatment for a utility-owned plant), and to record the present value of the expected lease payments as long-term debt on its balance sheet."¹⁶¹ The second rule may require SCE "to consolidate [certain counterparties in its balance sheet] for financial reporting purposes."¹⁶² SCE has not requested any specific relief related to these new accounting rules.

We observe here that consideration of such accounting rules may have been more appropriate in the COC proceeding. Since SCE contends that these new accounting rules are somewhat similar in effect to debt equivalence, SCE may seek further guidance from the Commission when appropriate and in the same manner as set forth in the COC proceeding.

I. Standard Offer Service

Constellation proposes a slice of load utility procurement mechanism to provide "standard offer service" (SOS). It is a wholesale power procurement approach whereby a jurisdictional public utility secures all or a portion of the generation supply to meet its retail load through a multi-year wholesale service contract or contracts with a third-party provider or providers. Constellation envisions that SOS would be procured through a competitive bid process approved by the Commission in advance and conducted with Commission oversight. Winning bidders would enter wholesale service supply contracts with the utility. The utility, in turn, would provide the ultimate retail service to its customers in fulfillment of its obligation to serve. Constellation explains that this service can be contrasted with the traditional procurement approach. In traditional service, utilities secure quantities of capacity or energy to serve loads subject to subsequent prudence reviews by regulators, while the SOS procurement approach uses a competitive solicitation process to secure generation service related to some percentage, or "slice" of the utility's load, which will vary in quantity from time to time.

According to Constellation, there are advantages to the utilities from SOS. It can transfer risks associated with load migration away from the utility to the wholesale supplier, removing the potential for new stranded costs or the need to impose new nonbypassable charges. It transfers some price risk and performance risk to the SOS provider. It promotes a diversity of suppliers and market entrance points, creating a portfolio of supply arrangements.

Constellation states that some form of the SOS approach is currently used in Maryland, New Jersey, Maine, Massachusetts, Connecticut, and New Hampshire. And since the close of the record in this case, the District of Columbia has adopted a SOS procurement mechanism modeled after Maryland's approach.

SOS may be a useful mechanism for wholesale procurement by LSEs, and it may be appropriate for California once it is further developed and considered. SOS is substantially different from the procurement methods currently being used by the IOUs, and we do not have the knowledge or confidence to mandate SOS at the present time or on the basis of the current record. This topic should be further developed by participants in the second generation of topics for the RAR process, for it is a companion to another topic to be considered, the development of markets for trading capacity.

J. Confidentiality

Consistent with the Commission's direction in D.04-01-050, it is our intention that many more categories of planning information will be open and will be considered so in our review of the IOUs' LTPPs. We have yet to determine if any information that routinely was considered confidential under former protocols might be deemed public when this decision is issued in final. We are still trying to balance the competing interests of the need of some confidentiality of IOU data to protect ratepayers, against the public interest in disclosure and the desire of intervenors to have better access to IOU confidential data to more fully participate in Commission proceedings. In D.02-08-071 we established the PRG process, and we continue to find it useful for certain procurement actions to be previewed and reviewed by the PRGs. While we favor "open decision-making" we need to be pragmatic about mitigating any adverse ratepayer consequences.

Since this OIR was issued, the Legislature passed, and the Governor signed, SB 1488¹⁶³ that directs the Commission to "initiate a proceeding to examine its current confidentiality rules under Pub. Util. Code §§ 454.5 and 583 and the California Public Records Act¹⁶⁴ to ensure that the Commission's practices under these laws provide for meaningful public participation and open decision making."

Currently under AB 57, that added Section 454.5 to the Pub. Util. Code, the Commission is to have in place procedures that ensure the confidentiality of any market sensitive information submitted by an IOU as part of its proposed procurement plan, while ORA and other consumer groups that are not market participants (NMP) have access to the information under confidentiality provisions. This provision of AB 57 was an attempt to balance the compelling ratepayer interest in ensuring that certain legitimately confidential information is kept out of the hands of those who can use it to manipulate wholesale energy markets, with promoting a sufficiently transparent decision-making process to allow for scrutiny and review by the legislature and the public.

Working from AB 57 and the additions to the Pub. Util. Code, when the Commission initiated R.01-10-024 on October 25, 2001, to establish policies and cost recovery mechanisms for generation procurement and renewable resource development, the assigned ALJ issued a ruling establishing a Revised Protective Order on May 1, 2002. That protective order remained in place throughout 2002.

In early 2003, the ALJ reopened the issue in response to concerns that certain MPs and other entities did not have adequate access to information under the existing protective order. A revised ALJ ruling issued on April 4, 2003 [joint Walwyn/Allen ALJ ruling] allowing the CAISO, and other NMP access to the same confidential information the consumer groups had with the direction that they must treat protected materials as confidential vis-à-vis third parties.

Following a request from SDG&E to amend the April 4, 2003, ALJ ruling to protect information submitted by parties to a RFP, the ALJ issued a ruling on December 1, 2003, modifying the previous protective order allowing certain bid information to remain confidential, but also soliciting comments on a further change to the protective order to incorporate a provision allowing outside attorneys and/or consultants to a MP who do not perform competitive duties for or on behalf of their client, and who execute a Non-Disclosure Certificate, to have access to materials relevant to the SDG&E RFP. Parties were directed to draft a Protective Order that paralleled language from an Amended Protective Order adopted by a FERC judge.¹⁶⁵ On January 14, 2004, following the receipt of comments on the FERC model, the ALJ issued a ruling adopting an Amended Protective Order (APO) that was substantially consistent with the FERC orders and that allowed the MPs access to Protected Materials following the FERC guidelines. As referenced earlier in this decision, this APO controlled confidentiality issues in this current procurement proceeding.

In preparation for review of the IOUs' LTPPs in this proceeding, in
D.04-01-050 the Commission expressed its desire to move towards more open and transparent decision making and asked the parties to submit comments on how to allow more access to utility data, but not at the expense of the ratepayer/consumer. Comments were received on March 1, 2004, and in summary, PG&E, SCE and SDG&E argued against increased disclosure, ORA/TURN favored more public disclosure and offered some guidelines, and the MPs were the most forceful in arguing for an open, transparent and competitive process. By that time SB 1488 was already in committee, so instead of issuing a new iteration of the January 14, 2004, APO we followed the guidelines implemented therein for this procurement proceeding.

We recognize our SB 1488 obligations and forthwith we will initiate a Rulemaking to fulfill our obligations under SB 1488. In initiating this new rulemaking, we will treat the CEC as a collaborating agency and not as a party so that we can develop confidentiality rules as closely aligned with one another as possible. We will also review the status and effectiveness of the PRGs in that Rulemaking. For purposes of this decision and our review of the IOUs LTPPs, we believe intervenors, including MPs, had sufficient access to the IOUs' background data and assumptions, if they chose to follow the guidelines of the January 14, 2004 APO to allow for a robust evidentiary hearing and development of the record to satisfy us that there was a full vetting of the important issues.

We also note that more intervenors, in particular the environmental groups, had access to the IOUs confidential data since they signed on to the APO. So in addition to the consumer groups, other NMP also had the benefit of reviewing all the utility data. None of the MPs chose to sign on to the APO. It may be the case that the utilities and the MPs have reached a point of equilibrium in that if the MPs had more access to utility information, the utilities may have demanded equal access to MP information.

¹⁴⁶ See also discussion of local capacity requirement and deliverability under: Enhanced Supply to Load Pockets.

¹⁴⁷ We note that this statement pertains to new resources within the SDG&E service territory and may not hold true for power purchases outside of San Diego that may encounter transmission constrains getting the power into the San Diego region thus lacking the resource deliverability the Commission has directed. We therefore underscore the importance of adhering to the direction provided in D.04-07-028 with regard to power purchases in the interim until the ISO market redesign proposal is fully implemented.

¹⁴⁸ D.04-01-050, p. 97.

¹⁴⁹ OIR 04-03-003, Assigned Commissioner's Ruling and Scoping Memo, June 4, 2004, p. 7.

¹⁵⁰ Ex. 34, p. 2-44

¹⁵¹ SDGE/McClenanan opening testimony, p. 12.

¹⁵² While not all financial hedges will result in collateral requirements, transactions such as financial futures or swaps will result in mark-to-market exposures similar to physical contracts.

¹⁵³ SCE Long-Term Plan, Vol.1, July 9, 2004, p.28.

¹⁵⁴ Id., p. 31.

¹⁵⁵ SCE opening brief, p. 131).

¹⁵⁶ Calpine direct testimony, pp. 18-19.

¹⁵⁷ Id., p. 47).

¹⁵⁸ SCE Long-Term Plan, Vol.1, Exhibit 73, pp. 47-50.

¹⁵⁹ EITF Issue 01-08, "Determining Whether an Arrangement Contains a Lease," May 15, 2003, effective for new or revised power contracts entered into after June 30, 2003.

¹⁶⁰ FASB Interpretation No. 46 (revised December 2003) "Consolidation of Variable Interest Entities-an interpretation of ARB No. 51."

¹⁶¹ SCE Long-Term Plan, Vol.1, Exhibit 73, p. 49.

¹⁶² Id., p.

¹⁶³ SB l488, (stats.2004,Ch.690, Effective September 22, 2004).

¹⁶⁴ Chapter 3.5 (commencing with Section 6250) of Division 7 of Title 1 of the Government Code.

¹⁶⁵ FERC Docket Nos. EL02-60-003 and EL02-62-003. See footnote 16.