This section addresses PG&E's proposal for a Winter Reliability Standard of a 1-in-10 year cold temperature event for its local transmission and central backbone facilities, and PG&E's proposal for a Winter Firm Capacity Requirement which establishes the level of firm capacity commitments to be made by Core Procurement Groups (CPGs)12 on behalf of core customers.
According to PG&E, these proposals have been raised because the reliability of PG&E's local transmission system, and the potential for supply curtailments, is of concern to noncore customers, especially gas-fired electric generation customers. If noncore customers are curtailed, it is likely that some electric generation customers will be forced to cease generating electricity, which is likely to result in service interruptions and higher costs for core electric customers.
PG&E proposes that the Commission adopt a Winter Reliability Standard which would maintain service to all customers during a 1-in-10 year cold temperature event. If this standard is adopted, PG&E would design its central backbone and local transmission facilities to meet the more stringent of (a) core-only demand under Abnormal Peak Day (APD) conditions, or (b) core plus noncore demand under a 1-in-10 year cold temperature event.
PG&E states that the proposed Winter Reliability for PG&E's system is consistent with the 1-in-10 year cold temperature event standard that was adopted in D.02-11-073 for noncore customers for both SoCalGas and SDG&E.
PG&E's current standard is to design its central backbone and local transmission facilities to meet the more stringent of (a) core-only demand under APD conditions, which is a 1-in-90 year cold temperature event, or (b) to serve 75% of core's APD demand plus all the noncore demand, which is about a 1-in-3 year cold temperature event. Adoption of the 1-in-10 year standard will require reinforcement of PG&E's local transmission system, which is explained more fully below. PG&E's current central backbone facilities and backbone capacity are expected to be sufficient to meet the recommended 1-in-10 year Winter Reliability Standard for the next few years.
If the Commission adopts this stricter Winter Reliability Standard, PG&E proposes that this standard be applied on an ongoing basis beyond 2004. The adoption of an ongoing standard will allow the market to have a greater degree of certainty about the future capability of PG&E's system, and the probability of capacity curtailments. Also, PG&E will be able to identify the facilities needed to support this standard, and to include the costs of these facilities in future applications.
PG&E's proposal to adopt a 1-in-10 year Winter Reliability Standard is not expected to require a reinforcement or expansion of the central backbone system over the next few years. However, as demand grows in specific geographic areas, and as storage withdrawal from all Northern California storage fields is increased, expansion of these facilities will likely be needed in the future. PG&E plans to monitor the central backbone system's ability to meet a 1-in-10 year reliability standard and propose system reinforcements as needed.
If PG&E's proposed 1-in-10 year Winter Reliability Standard is adopted, improvements to PG&E's local transmission facilities will be needed to ensure delivery of gas to transmission-level end-use customers and to PG&E's distribution facilities under these cold temperature demand conditions. PG&E estimates that the additional capital cost for this work is about $42 million13 for 2004-2007. For 2004, PG&E forecasts $2 million in capital expenditures to embark on the improvement of local transmission to meet the Winter Reliability Standard. If PG&E's Winter Reliability Standard proposal is adopted, PG&E states that this "would be authorizing PG&E to begin a four-year reliability improvement program to its local transmission system...." (Ex. 3, p. 4-6.)
The capacity of the backbone is generally determined by annual and seasonal needs. PG&E notes that a reserve margin or slack capacity guideline would be more appropriate than a winter reliability criteria for determining the required amount of backbone capacity to meet the annual and seasonal needs of PG&E's customers, and to help moderate commodity prices under a range of future conditions, including dry years. The Commission, however, has declined in D.90-02-016 and D.02-11-073 to adopt a specific reserve margin or slack capacity requirement. In D.02-11-073, the Commission noted that thoughtful system planning of utility systems was still needed.
Because system planning is still needed, PG&E proposes to continue to evaluate the capacity of the backbone receipt point and delivery capacity relative to forecast demand under various scenarios, including dry years. If PG&E identifies scenarios that could lead to extended periods of high utilization of its backbone system in the future, and the market does not appear to be responding, PG&E plans to work closely with the Commission to identify appropriate actions to avoid sustained high commodity prices due to intrastate capacity constraints on the PG&E backbone transmission system.
PG&E's proposal to adopt a 1-in-10 year Winter Reliability Standard does not directly impact PG&E's storage because PG&E's storage is based on the supply needs of its customers. However, since PG&E's storage fields provide a significant percentage of core's gas supply during a cold temperature event, PG&E's Core Procurement Department will need its current Gas Accord assignment of PG&E's gas storage, plus an additional assignment of 75 MDth/d of withdrawal capacity to meet its Winter Firm Capacity Requirement.
Since the additional 75 MDth/d assignment of storage withdrawal can be met with PG&E's existing storage capacity. PG&E does not expect its customers to request an expansion of storage for 2004. Beyond 2004, as core peak demand grows, PG&E's Core Procurement Department may need to contract for additional gas supplies to meet the Winter Firm Capacity Requirement, which could trigger an expansion of PG&E's storage.
PG&E proposes a Winter Firm Capacity Requirement for CPGs that determines the level of winter firm transportation and storage capacity commitments that CPGs must hold. PG&E proposes that the Winter Firm Capacity Requirement be set at the level needed to meet core demand for a minimum 1-in-10 year cold temperature event, which is consistent with the Winter Reliability Standard.
For the winter of 2004-2005, PG&E proposes a total core Winter Firm Capacity Requirement of 2,425 MDth per day through January 15, and 2,225 MDth per day through February 15. This calculation is based on the estimated core demand during a 1-in-10 year cold temperature event of 35 degree Fahrenheit.
Under the Gas Accord, the assignment of firm storage and transmission capacity to the core is enough capacity to meet core demand for about a 1-in-3 year cold temperature event. PG&E contends that the stricter Winter Firm Capacity Requirement will provide benefits to core customers, and is needed to capture the full benefits of improved delivery reliability for the noncore that the proposed Winter Reliability Standard would provide. That is, the more gas that core has access to, the less likely noncore supplies will have to be disrupted.
PG&E proposes that the Winter Firm Capacity Requirement for core firm storage and transmission capacity holdings by CPGs reflect expected weather patterns through the winter. From December 1 through January 15, the expected 1-in-10 year temperature is approximately 35 degrees Farenheit. After January 15, the expected 1-in-10 year temperature increases to approximately 38 degrees Fahrenheit. After February 15, the expected 1-in-10 year temperature increases to 43 degrees Fahrenheit. PG&E proposes that CPGs be required to hold enough firm capacity to meet their forecasted core load at the January 15 and February 15 temperature points, i.e., a 35 degree Fahrenheit forecast demand from December 1 through January 15, and a 38 degree Fahrenheit forecast demand from that point through February 15. After February 15, there would be no restrictions or requirements.
In order to meet the Winter Firm Capacity requirement, CPGs will need an additional assignment of 75 MDth/d of firm storage withdrawal above their current firm capacity holdings. The PG&E Procurement Policy section addresses the firm capacity holdings recommended for CPGs to meet the proposed requirement.
The Winter Firm Capacity Requirement would require CPGs to have gas supplies available, which reduces the need for CPGs to buy gas at the citygate during cold temperature events. By reducing core demand for immediate gas supplies during cold temperature events, the Winter Firm Capacity Requirement should help core to reduce its expected gas costs during cold temperature events, and help moderate gas prices at the citygate to the benefit of all customers.
PG&E also notes that the Winter Firm Capacity Requirement also benefits core gas customers by reducing potential EFO noncompliance charges that would be incurred if supply is not available during a cold temperature event, and the system must curtail noncore customers to free up gas supply for service to core customers.
If the Winter Reliability Standard is adopted, TURN suggests that the Commission consider moving from a cold year peak month allocator to a cold year non-coincident peak month measure to allocate local transmission costs.
LGS proposes that if PG&E's proposed Winter Firm Capacity Requirement is adopted, the Commission should require PG&E's Core Procurement Department to put the 75 MDth/d of withdrawal capacity out for bid, rather than allowing PG&E's at risk storage department to provide such service to the core.
LGS does not oppose the concept of a 1-in-10 year winter reliability standard, but is concerned that PG&E seeks such a standard with little evidentiary support, and then seeks to implement it in a fashion which is anti-competitive. LGS also points out that PG&E's proposals, such as reconfiguring the assignment of storage capacity and the creation of the Winter Reliability Standard has implications which extend far beyond the end of 2004, and should not be adopted in a one-year proceeding.
LGS contends that PG&E be required to support its reliability proposal before the Commission adopts it. PG&E has not demonstrated that its reliability proposals are needed, and thus has not met its burden of proof. The only thing that PG&E has proven is that PG&E's witness has admitted that the sole support for these proposals is that the Commission adopted a similar standard for SoCalGas and SDG&E. (3 RT 191-192.)
ORA states that the winter reliability proposals require complicated and time-consuming assessment, and that PG&E has presented no concrete evidence that its current standard needs improvement. TURN states that a 1-in-10 standard may ultimately make sense, but that determination should be made in a forum in which there is adequate time and staff resources to perform the necessary analysis. LGS states that PG&E has not performed that analysis. PG&E's rebuttal testimony states that there was no need for a detailed cost-benefit analysis for the standards. LGS asserts that PG&E is simply trying to piggyback on another Commission decision which addresses different utilities with a system that is not the same as PG&E's.
If PG&E demands that studies of its opponents' proposals be provided, then PG&E should also provide such studies of its own proposals, which PG&E has not done for the Winter Reliability Standard. LGS asserts that changes of the magnitude in PG&E's proposals should not be made without presentation of appropriate analysis and supporting evidence by the party proposing the changes.
LGS notes that PG&E's opening brief at page 7 acknowledges that its winter reliability proposals are "not market structure issues, and the Commission can easily decide to accept, reject, or modify PG&E's proposals in these areas within the context of the overall Gas Accord market structure." PG&E also states at page 17 of its opening brief that its winter reliability proposals "are adjustments to improve the operation and reliability of PG&E's system under the Gas Accord structure, not changes to the fundamental structure." If PG&E believes these reliability proposals are important, it should conduct appropriate studies and present them again with better support in a future proceeding to which the proposals are related. When PG&E admits that these two reliability proposals are unrelated to the gas market structure, and when there is a lack of support for such proposals, such proposals should be rejected.
As for the 75 MDth/d of storage needed to support the Winter Firm Capacity Requirement, LGS contends that there were significant inconsistencies regarding the source of this capacity. In its direct testimony, PG&E stated that "PG&E Core Procurement will need its current Gas Accord I assignment of PG&E's gas storage plus an additional assignment of 75 MDth/d of withdrawal capacity to meet its Winter Firm Capacity Requirement as proposed below." (Ex. 1, p. 4-9.) The same testimony goes on to state that the additional withdrawal capacity "can be met with PG&E's existing storage capacity...." (Ex. 1 at 4-9.) LGS believes that the clear implication of this testimony is that the 75 MDth/d of withdrawal capacity assigned to at-risk storage in the original Gas Accord would be reassigned to the core. LGS' opening testimony was based on that assumption. (See Ex. 19 at 3.)
After PG&E and the other parties submitted testimony, it became known that PG&E was proposing a wholesale revision of the storage assignments contained in the Gas Accord settlement agreement. Rather than reassigning withdrawal capacity from at-risk storage to the core, PG&E is conducting what amounts to a bottoms-up redesign of the storage system assignments to various users. According to PG&E, the 75 MDth/d is available because PG&E increased withdrawal capacity over the period since adoption of the original Gas Accord, and because of the existence throughout that period of a peaking agreement between PG&E's Core Procurement Department and PG&E's at-risk storage department.
LGS asserts that the assignment of 75 MDth/d to the core, without giving third party storage providers the opportunity to bid for that capacity, is anticompetitive and not in the best interests of captive core customers. LGS is concerned that the proposed Winter Firm Capacity Requirement is just a way for PG&E to market its own storage on a rolled-in basis to captive ratepayers to compete against LGS and Wild Goose Storage Inc. (Wild Goose) in the marketplace.
Should the Commission adopt PG&E's proposed Winter Firm Capacity Requirement, it should require PG&E's Core Procurement Department to put the 75 MDth/d of capacity out for bid. LGS notes that TURN, whose charge is protect core ratepayers, also agrees that such capacity should go out for bid.
NCGC supports PG&E's proposal for a Winter Reliability Standard, PG&E's proposal for establishing a Winter Firm Capacity Requirement for CPGs, and for expanding the local transmission system. The adoption of the Winter Reliability Standard for PG&E is consistent with the standard established by the Commission for SoCalGas and SDG&E in D.02-11-073.
NCGC points out that in order to meet the proposed Winter Reliability Standard, PG&E will need to reinforce its local transmission system, and PG&E's Core Procurement Department will need to acquire additional withdrawal storage capacity in order to meet the standard. Backbone transmission would not require expansion. PG&E, however, proposes to evaluate the capacity of the backbone system, and to work closely with the Commission to identify appropriate actions to avoid sustained high commodity prices due to intrastate capacity constraints on PG&E's backbone transmission system. NCGC supports PG&E taking on such a role since capacity expansions are less costly than commodity price spikes that can occur if transmission capacity is constrained. The adoption of the Winter Reliability Standard will reduce the costs imposed on noncore customers in the event of a gas curtailment.
TURN suggests that if the Commission adopts the 1-in-10 year standard, that the Commission should consider moving from a cold-year peak month allocator for allocating local transmission costs to a cold year non-coincident peak month measure. NCGC says there is no merit to TURN's proposal. If local transmission facilities are sized to meet demand during a 1-in-10 year cold temperature event, that means the local transmission system is sized to meet coincident demand by all customers during such an event. NCGC says it would be inconsistent to size the local transmission system to meet coincident demand and then adopt a marginal demand measure based upon non-coincident demand.
ORA contends that the assessment of PG&E's Winter Reliability Standard proposal is complicated and time consuming, and that such an assessment has not been done by ORA given the time constraints. ORA notes that PG&E has not presented any concrete evidence that its current standard is in need of improvement. ORA also contends that it took two years to review the Winter Reliability Standard for SoCalGas and SDG&E.
PG&E's proposal for a 1-in-10 year Winter Reliability Standard would replace the less stringent 1-in-3 year winter reliability standard. ORA asserts that the impact of this proposal goes beyond 2004 because PG&E proposes to implement it over a four-year period. The projected cost to upgrade the standard was initially estimated at $34.1 million, but in PG&E's updated testimony, has grown to $42 million. Although PG&E proposes that authorization be granted now, and that the implementation details be examined in the future, ORA contends that adopting the multi-year standard with uncertain costs and uncertain implementation parameters is contrary to the interest of ratepayers who may be subjected to huge rate increases several years down the road when the project is completed.
ORA is opposed to examining the winter reliability issue in this proceeding, but is not opposed to examining this issue in a future comprehensive proceeding. ORA contends that the assessment of winter reliability standards is complicated and time consuming, and requires extensive inquiry into the adequacy of the utility's current standards, an analysis of the need for future improvement, cost studies, and a careful cost allocation methodology. ORA contends that PG&E has not presented concrete evidence that its current standard is in need of improvement, and there was insufficient time in this proceeding to properly evaluate PG&E's proposed Winter Reliability Standard.
ORA also points out that because there is a correlation between PG&E's Winter Reliability Standard and its proposed increased core penalties, if the Commission rejects PG&E's proposed winter reliability standard, the Commission should also avoid considering PG&E's proposed OFO or EFO penalties.
Palo Alto asserts there is no reason to adopt the proposal at the present time since the benefits in 2004 are de minimis.
Palo Alto also asserts that despite appearances, the proposed core firm storage requirement will not result in a 75 MDth/d increase in the physical amount of storage withdrawal capacity actually held by CPGs. PG&E's witness testified that CPGs currently have access to 100,000 Dth per day of additional firm withdrawal capacity under an agreement with the California Gas Transmission (CGT) group. (3 RT 200-201.) To comply with the 1-in-10 year firm storage requirement, CPGs would simply exchange this agreement for an additional 75,000 Dth per day of standard firm storage service. As a result, there would not be a 75,000 Dth per day increase in CPGs' firm rights, as appeared to be the case in PG&E's prepared testimony in Chapter 6 of Exhibit 1.
TURN suggests that PG&E's proposal for a Winter Reliability Standard and Winter Firm Capacity Requirement go beyond the scope of this proceeding as set forth in the February 26, 2002 scoping memo. While a 1-in-10 standard may ultimately make sense, TURN asserts that such a decision should be made in a forum in which there is adequate time and staff resources to perform the necessary analysis. TURN contends that these two proposals require engineering analysis by the Commission's staff, which has not occurred because of the limited time frame of this proceeding.
TURN contends that PG&E's proposal shifts costs away from noncore customers, who will receive more reliable service under the proposal, onto core customers who will pay more for the facilities that will be built to improve service to the noncore.
TURN points out that PG&E already has a more stringent 1-in-90 year cold temperature event standard for serving core demand, and a 1-in-3 year cold temperature event standard for serving noncore customers. Thus, the explicit goal of the new Winter Reliability Standard is to "improve noncore customer and gas-fired electric generation reliability." (Ex. 3, p. 4-1.) In order to meet this standard, PG&E forecasts investing approximately $42 million in local transmission projects between 2004 and 2007.
Although PG&E claims that its proposed standard is consistent with the standard adopted for SoCalGas and SDG&E in D.02-11-073, TURN points out that PG&E's proposal is to maintain service to all customers during a 1-in-10 year cold temperature event. The SoCalGas and SDG&E decision only adopted the 1-in-10 year standard for firm noncore service. TURN states that if $42 million is going to be spent to improve the level of service to noncore customers, those noncore customers should be required to commit to firm service on a multi-year use-or-pay basis. Also, PG&E's proposal would shift costs away from noncore customers, who would be receiving more reliable service, to core customers who would end up paying more for the facilities being built to improve service to the noncore. TURN asserts that the inequities of PG&E's proposal should be more closely examined.
If a higher standard of reliability for noncore service is adopted, TURN recommends that the Commission consider moving from a cold-year peak month allocator to a cold-year non-coincident peak month measure. TURN contends that such a methodology would better capture the impact on the system of those noncore customers whose maximum usage occurs in a month other than January. Since the local transmission system must be "sized to meet the maximum demand of local or specific customers," whenever it occurs, a large noncore customer with a non-January peak load could require the installation of a larger local system, especially if there is not a heavy core load in the area. (See Ex. 1 at 14-23; Ex. 77, p. 16.) TURN asserts that PG&E's testimony suggests that even though the planning criterion is based on a cold day, there appears to be a significant possibility that actual planning for local transmission reinforcements will be driven by electric generator demands during non-winter conditions.
LGS suggested that PG&E's Core Procurement Department should not assume that PG&E will be the provider of additional storage needs. TURN agrees that the core should be allowed to shop around like any other gas customer, and that a bidding process may be the best way to meet any increased core storage needs. However, due to the potential conflicts of interest involved, the Commission should oversee any such process to ensure that core customers are not being used to cross-subsidize new utility facilities when cheaper competitive opportunities exist.
PG&E proposes a Winter Firm Capacity Requirement that establishes the level of firm capacity commitments which must be made by CPGs on behalf of core customers. Wild Goose does not oppose the implementation of such a requirement. However, it does oppose the manner in which PG&E proposes that the core meet the new capacity requirement, through an assignment of an additional 75 MDth/d of storage withdrawal from PG&E-owned at-risk storage. Wild Goose contends that PG&E's proposal does not account for the presence of two independent storage providers on its system who should be given the opportunity to compete to provide the additional withdrawal capacity to the core, as well as to the noncore. Wild Goose requests that the Commission clarify that independent storage providers are authorized to compete for provision of service to the core.
PG&E notes that its proposed Winter Reliability Standard consists of two elements. The first element is the Winter Reliability Standard, which, if adopted, would guide PG&E's design of its backbone and local transmission system to maintain service to all customers during a 1-in-10 year cold temperature event. Adopting the proposal would start the implementation of a four-year program (2004-2007) to upgrade its local transmission system to the more stringent planning standard for service to both core and noncore customers. PG&E will also continue to ensure that its local transmission facilities can serve all core customers during an APD, a 1-in-90 year event.
The second element of the proposed Winter Reliability Standard is that CPGs, including PG&E's Core Procurement Department, will be required to meet the Winter Firm Capacity Requirement. This means that the core will need to obtain sufficient firm transmission and storage capacity to meet their forecasted demand under 1-in-10 year cold temperature condition. To meet this Winter Firm Capacity Requirement, an additional 75 Mdth/d of firm withdrawal capacity needs to be assigned to the core. This requirement will reduce the CPGs' reliance on noncore supply diversion or curtailment, and improve reliability for noncore customers.
PG&E contends that having the Commission adopt the same Winter Reliability Standard as SDG&E and SoCalGas will promote a common level of firm gas transmission service reliability throughout the state. The adoption of the proposed Winter Reliability Standard for 2004 will allow PG&E to properly plan for future facility additions, and for CPGs to make the additional transportation and supply arrangements to meet the higher reliability standard. If the Commission does not adopt the proposed Winter Reliability Standard, or action is delayed, then the facilities and commitments to meet this standard will not be in place should cold winter conditions occur, or it will delay the necessary upgrades to meet the proposed standard.
PG&E asserts that its Winter Reliability Standard proposal is timely and within the scope of this proceeding. If adopted, the Winter Reliability Standard and Winter Firm Capacity Requirement will increase reliability, mitigate gas price spikes, and reduce core noncompliance penalties.
PG&E's proposal to adopt a 1-in-10 year Winter Reliability Standard is not expected to require reinforcement or expansion of the central backbone system over the next few years. However, the proposed Winter Reliability Standard will require improvements to PG&E's local transmission facilities to ensure delivery of gas to transmission-level end-use customers and to its distribution facilities. PG&E estimates that these improvements will cost about $42 million in capital expenditures over the four-year period of 2004 to 2007. Only about $2 million is proposed to be included in 2004 rates. The costs of the improvements beyond 2004 would be included in rates in following years, and subject to review and approval through the Commission's application process. PG&E notes, however, that if the Commission approves the proposed Winter Reliability Standard, the approval would authorize PG&E to begin a four-year reliability improvement program to its local transmission system.
LGS, TURN, Palo Alto and ORA all call for additional analysis of PG&E's Winter Reliability Standard proposal. PG&E asserts that none of them have explained why the SoCalGas/SDG&E decision in D.02-11-073 should not apply to PG&E's service territory. PG&E contends that the Commission has already made a determination in D.02-11-073 of the benefits of a 1-in-10 year design standard. The three main benefits of higher reliability apply to Northern California, as well as to Southern California. These three benefits are: (1) a higher reliability standard reduces service interruptions to the noncore market, and the types of businesses representing the noncore market are the same in the north and the south, and the impacts of curtailment are the same; (2) a higher reliability standard reduces spot gas price increases during periods of high demand; and (3) a higher reliability standard reduces electric generator outages.
Although the Commission spent two years studying the issue for SDG&E and SoCalGas, PG&E asserts that a similar effort is not needed in Northern California. To suggest that further study is needed now, is basically suggesting that the Commission erred in its decision regarding SDG&E and SoCalGas.
LGS also opposes PG&E's winter reliability proposal because PG&E's Core Procurement Department does not propose to bid out the additional 75 Mdth/d of storage withdrawal capacity that it would need to meet the Winter Firm Capacity Requirement. Wild Goose opposes PG&E's proposal that the 75 Mdth/d of additional withdrawal capacity would not be put out to bid. PG&E contends that these objections are misplaced and based on self-interest. PG&E asserts that D.93-02-013 obligates PG&E to provide the storage capacity for core reliability needs. Unless this policy is changed, the core cannot seek bids from third-party storage providers to provide the added storage withdrawal capacity to meet reliability needs. PG&E asserts that since the Commission has not yet unbundled PG&E's obligation to provide core storage, the suggestion that PG&E's proposal is anticompetitive is absurd. If LGS or Wild Goose wants to change Commission policy, then it should develop such a proposal and present it to the Commission.
PG&E points out that its rebuttal testimony demonstrates that the increase in the capital expenditures related to the Winter Reliability Standard was to reflect the increase in the installed unit cost ($/ft) for current pipeline installation costs.
After reviewing the record in this proceeding, and the arguments of the parties, there are several reasons why PG&E's Winter Reliability Standard and the related Winter Firm Capacity Requirement proposals should not be adopted at this time.
First, PG&E seeks to apply the 1-in-10 year cold standards that were approved for SDG&E and SoCalGas in D.02-11-073 to PG&E's transmission system. However, D.02-11-073 was a proceeding opened by the Commission to specifically investigate the "adequacy of the SoCalGas and SDG&E gas supply and transmission system to provide service to present and future core and noncore customers of SDG&E." (D.02-11-073, p. 3.) Unlike that proceeding, the central focus of this proceeding is to address the gas market structure for PG&E's gas transmission and storage systems, and to set rates for 2004.
PG&E's own witness acknowledged on cross examination that PG&E's proposals for the Winter Reliability Standard and the Winter Firm Capacity Requirement were based solely on the Commission's adoption of the 1-in-10 year reliability standard adopted for SoCalGas and SDG&E in D.02-11-073. (3 RT 191-192.) PG&E provided very little support to justify why a proceeding investigating a specific set of circumstances in Southern California should be applied equally to PG&E.
Our second reason for not adopting the proposals is that the Winter Reliability Standard is a design planning tool that the utility uses to design its transmission system to meet certain design criteria. The planning and design of the size of the transmission facilities to serve customer load, is not, as PG&E acknowledges, a gas market structure issue. Instead, as noted by TURN, it is an engineering issue that requires careful review. ORA was unable to provide that kind of assistance in this proceeding.
The design and planning of the transmission system to address a 1-in-10 year cold temperature event also has numerous ramifications throughout this proceeding. As noted in the matrix of proposals, many of PG&E's other proposals are specifically tied to the Winter Reliability Standard. In order to thoroughly evaluate all of these proposals, we must start with a thorough evaluation of the root proposal. That evaluation cannot hinge solely on a decision which was opened to investigate the ability of the transmission systems of SDG&E and SoCalGas to serve SDG&E's customers. In addition, PG&E has not provided any documentation to support its need to have a stricter design standard. Without a thorough understanding of the need for a stricter standard, we should not allow PG&E's stricter and more costly proposal to go forward and impact other elements of the gas market structure.
We also note that a system-wide diversion of PG&E's noncore customers has never been called. In addition, the current design criteria for PG&E's transmission system is to meet the more stringent of (a) core demand under APD conditions, which is a 1-in-90 year cold temperature event, or (b) 75% of core's APD demand plus all noncore demand, which is about a 1-in-3 year cold temperature event. Although the 1-in-10 year cold temperature event may be a worthy goal and warranted at some point, PG&E has not met its burden of proving in this proceeding that the Winter Reliability Standard is needed at this point in time.
The third reason for not adopting the proposals is there is still uncertainty regarding future regulatory authority over PG&E's transmission system. The Bankruptcy Court has not yet addressed this issue. PG&E states quite clearly in its testimony that if we approve the Winter Reliability Standard proposal, we are authorizing PG&E to begin a four-year process of upgrading its local transmission facilities to meet the 1-in-10 year requirement. Due to the uncertainty of whether we will retain jurisdiction over PG&E's transmission facilities, it does not make sense at this time to commit to a four-year capital expenditure program which may cost $42 million or more.
The fourth reason for not adopting the proposals is that the cost of meeting the Winter Reliability Standard is still uncertain. Although PG&E forecasts that the upgrade of local transmission facilities will cost $42 million over four years, PG&E's witness acknowledged that the amount was "based on a very quick and dirty analysis of the types of expansions that would be needed to meet that standard that you may not need to incur in the absence of that standard." (2 RT 104.) In addition, PG&E's testimony noted if new power plants are located in areas of local transmission constraints, costs could change significantly.
If we approve PG&E's Winter Reliability Standard proposal, we would be embarking on a four-year commitment of upgrades with costs that are subject to further change. Given the high prices for natural gas for the foreseeable future, and expected higher winter heating bills, it is unwise to adopt PG&E's proposals to incur additional costs without adequate justification. In addition, the adoption of PG&E's Winter Reliability Standard proposal would also affect other proposals of PG&E in this proceeding, which have a cumulative effect on the cost of service and on PG&E's overall revenues.
For the reasons stated above, we do not adopt PG&E's proposal for a Winter Reliability Standard for the design and planning of PG&E's transmission system for 2004 and beyond, and we do not adopt PG&E's proposal for a Winter Firm Capacity Requirement. These proposals may be raised again when we review the type of gas structure that should be in place for 2006 and beyond, or in another proceeding where the long-range service aspects of PG&E's gas transmission services are being examined.
Since we do not adopt the Winter Reliability Standard, there is no need to address the proposals of TURN and LGS concerning the peak month allocator, and storage service competition, respectively.
Due to the rejection of PG&E's Winter Reliability Standard and related Winter Firm Capacity Requirement, other PG&E proposals in this proceeding are affected, as well as the associated costs. These other proposals are addressed in the other sections of this decision.