IV. Discussion of the Issues
A. Introduction
The principal issues before us are: (1) whether PG&E's proposal for a 1-day-in-10-year peak day planning standard should be adopted as the core gas reliability planning standard for PG&E, and whether sufficient incremental storage capacity should be acquired to meet this standard; and (2) whether PG&E's proposed credit requirements should apply to third-party storage providers who offer to provide the incremental storage capacity.
Most of the process and timing issues relating to the Request for Offer (RFO) process for the solicitation of incremental storage capacity were agreed to in Exhibit 20. We discuss all of these issues below, along with a discussion of the other issues raised in the scoping memo.
B. PG&E Proposal for a One-Day-In-10-Year Planning Standard
PG&E proposes that a reliability planning standard of a 1-day-in-10-year peak day be adopted for PG&E's intrastate pipeline capacity and firm storage withdrawal capacity for its core customers.3 The planning standard that is adopted determines the appropriate level of pipeline capacity and storage capacity that PG&E should hold on behalf of its core customers. PG&E proposes that firm incremental storage capacity for the core be added to meet its proposed planning standard if the additional storage capacity can be acquired at a reasonable market cost.4 According to PG&E, adding additional storage is the most cost-effective way of meeting the planning standard.
The 1-day-in-10-year peak day planning standard translates into a system composite temperature of 35 degrees Fahrenheit. A 35-degree day has an expected recurrence interval of once every 10 years during the December to January timeframe. The 1-day-in-10-year peak day demand for 2007-2008 is estimated to be 2,584 thousand decatherms (MDth). Based on current projections, PG&E expects that core demand will grow by between 20 and 30 MDth per day per year. PG&E proposes that the core capacity holdings required to meet the 1-day-in-10-year peak day standard be reassessed on an annual basis after the 2007-2008 period.
PG&E's core customers currently have pipeline capacity and storage withdrawal capacity of about 2482 MDth per day, which is sufficient to meet a 1-day-in-4-year peak day event. To serve an event colder than the 1-day-in-4-year peak day, core load would have to be served from gas purchased on the spot market, or through the diversion of noncore gas supplies in accordance with Rule 14 of PG&E's gas tariffs.
The adoption of the 1-day-in-10-year peak day standard will require approximately 100 MDth per day of additional withdrawal capacity, coupled with sufficient inventory to meet that level of withdrawal over 10 days.5 The exact level of storage inventory needed to provide the additional 100 MDth of withdrawal capacity is difficult to determine at this point because the gas storage fields have different operational and cost characteristics.6 PG&E believes that the storage inventory capacity will be at least 1 million decatherms (MMDth), but more likely to be about 2 to 3 MMDth.
TURN is opposed to PG&E's proposal to adopt the 1-day-in-10-year peak day planning standard for core customers, the need for incremental storage to meet this proposed standard, and PG&E's proposal that the core pay for the cost of this incremental storage.
All of the other active parties support PG&E's proposal for the
1-day-in-10-year peak day planning standard for core customers, as well as the related proposals, as set forth in the Partial Settlement.
PG&E, and some of the other parties, contend that the proposals for the 1-day-in-10-year peak day planning standard for the core and the incremental storage capacity should be adopted for a number of reasons. The adoption of the proposals will increase the core's reliability to serve its own needs during a peak day event. If the current planning standard remains unchanged, and a peak day event occurs, it is likely that the winter weather pattern will result in less flowing supplies through PG&E's Redwood Path transmission facilities due to economic pull by north-of-California gas consumers. The supply shortages may also lead to diversions of noncore supplies. By increasing the core's reliability standard, this will reduce the core's reliance on diversions of noncore gas during a peak day event, and having to buy needed gas supplies on the spot market. They point out that diversions of noncore gas will impact electric generation and electric generation customers, and will disrupt the operations of other noncore customers who use natural gas. The adoption of the proposed standard will lead to increased storage capacity, which provides the core with additional seasonal price arbitrage opportunities by injecting gas when prices are low and withdrawing the gas when prices are high. They also point out that the cost of meeting the 1-day-in-10-year peak day planning standard can be accomplished for less than a 0.5% increase in core customer rates.
TURN contends that PG&E's noncore gas customers will be the beneficiaries of the 1-day-in-10-year planning standard for the core. Under PG&E's proposal, core customers will end up paying for the costs associated with the new standard, while the noncore will not have to pay for any of these costs. In addition, the noncore will be able to continue their current procurement practices of relying on the market to supply their gas, which there should be more of because of the core's additional storage, while minimizing their own storage needs. By adopting PG&E's proposals, TURN believes that the noncore is benefiting at the expense of the core.
In deciding whether PG&E's proposals should be adopted, we need to weigh and consider a number of factors as pointed out by the parties. First of all, the storage capacity for PG&E's core customers has not increased since the Commission first adopted the Gas Accord for PG&E in August 1997 in D.97-08-055 [73 CPUC 2d 754]. In that decision, firm storage inventory for the core was set at 33.5 MMDth, and has remained unchanged in the subsequent decisions addressing renewal of the Gas Accord provisions. (See 73 CPUC 2d at 808; D.03-12-061 at p. 102;
D.04-12-050, Ex. 1, p. 6.) Although the core storage inventory has remained the same since the Gas Accord decision was adopted, core gas demand has grown since that time. By adopting PG&E's proposed planning standard for the core, additional storage can be added for the core's benefit.
The second consideration is that the diversion of noncore gas to help remedy the core's supply shortages was initiated at a time when electric generators had the ability to switch to an alternative fuel in the event natural gas was not available. Due to air quality restrictions, most of the electric generators can no longer use alternative fuels. As a result, if diversions of noncore gas were to occur, the diversions would have severe economic consequences for California's economy. A diversion of noncore gas is likely to reduce the amount of electricity that is generated in California, drive up the price of electricity, and impact the customers who rely on that electricity. In addition, other noncore customers who use natural gas in manufacturing and production will be impacted if diversions occur. The adoption of the 1-day-in-10-year planning standard for the core, and the incremental storage capacity for the core, will alleviate these potential impacts by reducing the core's reliance on having to divert noncore gas during a peak day event. In light of the changes in recent years concerning electric generation, we agree with DRA's argument that allowing the core to rely on the diversion of noncore supplies to meet core load is not an appropriate long-term planning or policy strategy for the core to pursue.
In addition, adopting PG&E's planning standard will reduce the reliance on diversions of noncore gas and the diversion penalties the core would have to pay to the noncore in the event of a diversion.
A third consideration is to consider the planning standard that other utilities have. PG&E relied on a study of other utilities in the United States to support its proposal for a 1-day-in-10-year planning standard. TURN argued that the study did not justify the adoption of PG&E's proposed planning standard. We are not persuaded that the study justifies the use of PG&E's proposed planning standard. Many of the utilities referenced in that study operate in temperature zones and circumstances that are different from what PG&E is faced with.
An appropriate comparison, however, is the planning standard that is in place for San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas). In D.02-11-073, the Commission adopted a 1-day-in-10-year planning standard for noncore customers of SDG&E and SoCalGas, and kept in place the core planning standard for SoCalGas of a 1-day-in-35-year standard.7 PG&E's current core holdings of firm transmission capacity and firm storage withdrawal are equivalent to approximately a 1-day-in-4-year event. When one considers the growth in core load, that core storage inventory has not increased since late 1997, and the current planning standards for the other California gas utilities, the adoption of a 1-day-in-10-year planning standard for PG&E's core customers makes sense.
A fourth consideration is the modest cost of adopting PG&E's proposed standard. PG&E estimates that the cost of adopting the 1-day-in-10-year peak day planning standard will be between $2 million to $6 million, and will result in an increase to PG&E's core customers of less than 0.5%. DRA estimates that the monthly bill impact on an average residential customer's monthly bill will increase about 8 to 40 cents, depending on the cost of the incremental storage capacity that is acquired for the core.
The cost of meeting PG&E's proposed planning standard is small as compared to what could happen to gas prices and the gas supply in the event of a peak day event. Having more supply capacity on hand will reduce the core's exposure to the spot market during extreme temperature events. Simply put, the cost associated with the planning standard is cheap insurance against the probability of a peak day event occurring.
A fifth consideration is who benefits the most from PG&E's proposed planning standard and the incremental core storage capacity. TURN argues that it is the noncore that benefits the most because they do not have to do anything or pay anything. Instead, the noncore can continue their current practice of relying on the spot market to fulfill their gas needs instead of acquiring sufficient pipeline capacity and storage capacity. TURN contends that if the core has to increase its storage in order to meet the new planning standard, the core's action will result in more gas being available because the core will not be competing with the noncore for spot gas purchases. In addition, by having more gas available to the noncore in the spot market, the noncore will not have an incentive to acquire more pipeline capacity or storage capacity to meet their needs. TURN contends that these benefits that accrue to the noncore are paid for at the expense of core customers.
We agree with TURN that noncore customers will receive some benefit as the result of the adoption of the 1-day-in-10-year planning standard for the core. To meet this increase in planning, PG&E proposes that the core acquire additional storage capacity. This additional storage will confer some benefit to the noncore because the core will not have to compete as much with the noncore during cold winter events. However, the primary beneficiary of the planning standard will be the core because they will have more gas available to meet a peak day event, the core will not have to rely as much on the spot market, and the possibility of diverting noncore gas will be reduced.
The sixth consideration is that under the proposed RFO process, as set forth in Exhibit 20, TURN and DRA will be a part of the evaluation process and have a voice in deciding whether the incremental storage offers are reasonably priced or not. The participation of DRA and TURN in the evaluation process will help ensure that the cost of meeting PG&E's proposed planning standard will be minimized.
Based on all of the above considerations, we believe that PG&E's proposed planning standard should be adopted for the core. It is clear that the adoption of the planning standard will primarily benefit PG&E's core customers. The planning standard will result in an increase in gas supply reliability for the core. This is important given the growth in core gas demand, and the inability of electric generators to use alternative fuels in the event of a gas diversion. The cost of the planning standard is very modest as compared to the economic turmoil that could result if we do not adopt the planning standard for the core and a peak day event were to occur. Our role as regulators is to protect both the core and noncore customers. The cost of adopting PG&E's proposed planning standard strikes an appropriate balance with what could happen to the core and noncore if PG&E's planning standard is not adopted. The Commission should adopt the 1-day-in-10-year peak day planning standard for PG&E's core customers, PG&E should be allowed to acquire the incremental storage capacity needed to meet this core planning standard, and PG&E should be allowed to recover the costs of meeting the planning standard in the monthly core procurement rates. PG&E should also be permitted to seek out additional storage opportunities that provide economic benefits to the core, and to recover those costs from the core. (See Ex. 1, pp. 2-2 to 2-3, 2-9; Ex. 20, § B.1.)
In the event PG&E cannot obtain incremental core storage at a reasonable market price to meet the 1-day-in-10-year peak day standard, PG&E should obtain sufficient firm intrastate and interstate pipeline capacity, and/or firm peaking supply contracts at either the city gate or the California border on a temporary basis, to meet the standard using the processes approved in D.04-09-022.
C. PG&E Creditworthiness Proposal
The other issue that was heavily contested is whether PG&E's standard credit policies should apply to the independent storage providers who submit bids for storage products. PG&E proposes that the third-party storage provider meet the credit requirements that PG&E applies to its other vendors as set forth in PG&E's Rule 25 of its tariffs. In order to meet PG&E's creditworthiness standard, the storage provider must be rated by a rating agency. If no rating is available, then the storage provider must provide credit assurances that equal 100% of the replacement cost of the gas to be stored. According to PG&E, the 100% credit assurance matches PG&E's risk appetite for its exposure by storing gas into a field controlled by another party.
Under PG&E's credit policies, it assesses the creditworthiness of a publicly owned company, with whom it is contemplating contracting with, by looking at the company's debt rating. PG&E then determines from the rating how much of an unsecured credit line should be given. In general, if a company is not rated by a rating agency, PG&E does not give them an unsecured credit line because without a rating, it is difficult for PG&E to assess a party's probability of default. PG&E would then require the non-rated party to provide credit support in the form of a cash deposit, a guarantee from an investment grade entity, a letter of credit, or a surety bond from an acceptable credit support provider in a form and substance that is satisfactory to PG&E.
As part of PG&E's evaluation of the creditworthiness of a party, it also looks at the type of risk associated with the transaction it is planning to enter into, as well as the length of the transaction. For example, PG&E parked gas with LGS for several days without requiring a credit assurance. But for longer term transactions, without a rating or empirical evidence, it is difficult for PG&E to assess the probability of performance.
PG&E asserts that its credit policies should apply to independent storage providers because of the risks associated with storing gas with that provider. According to PG&E, the risk is that the storage provider may fail to return the stored gas pursuant to the terms of the storage contract. The financial loss from such a risk is the replacement cost of the gas that was stored but which has not been returned. The financial loss could also include curtailment penalties if replacement gas is not available and curtailments are required. PG&E asserts that the storage provider should be required to have adequate credit support or assurance to offset the replacement cost of the gas and other potential losses.
Under PG&E's credit policies, PG&E's California Gas Transmission (CGT) department would be considered creditworthy because CGT is backed by PG&E's credit rating. If CGT were to bid on the incremental storage capacity, PG&E would not require CGT to post any credit support or assurances.
Wild Goose and LGS oppose the adoption of PG&E's credit policies for determining the creditworthiness of a storage provider offering incremental storage capacity. They are concerned that PG&E's credit policies will impact the bidding by independent storage providers to offer incremental core storage capacity, or discourage them from bidding in the RFO process. If PG&E's credit policies are adopted, since neither Wild Goose nor LGS are publicly traded companies, PG&E would require them to provide credit support, in a form acceptable to PG&E, for an amount equal to the full replacement cost of the gas which PG&E will be storing with the storage provider. The amount of credit support that Wild Goose and LGS would have to provide is estimated to range from $9.5 million to $47.5 million.8 In addition, Wild Goose and LGS contend that there is a cost associated with having to procure the credit support, and that such a requirement will tie up the capital of the storage providers. In contrast, CGT would not be required to provide any credit support.
The record in this proceeding contains ample evidence and arguments on the factors we should consider in deciding whether PG&E's current credit policies should apply to the provisioning of incremental storage capacity by independent storage providers. We first turn our attention to PG&E's proposal to use its current credit policies that are contained in PG&E's Rule 25.
Rule 25 of PG&E's tariff applies to the situation of where a customer of PG&E is purchasing or receiving gas products or services from PG&E. In order to receive the gas products or services from PG&E, the customer must meet the credit requirements of PG&E that were described earlier. Wild Goose and LGS assert that the credit policies in Rule 25 should not apply to them because they are not purchasing or obtaining products or services from PG&E. Instead, as storage providers, they will be the ones who will be providing the storage service to PG&E, and PG&E will be paying them for the service.
We agree with Wild Goose and LGS that the transactions under the RFO for incremental storage capacity are different from the transactions contemplated in PG&E's Rule 25. We recognize, however, that PG&E core procurement customers are exposed to risk if PG&E stores gas with Wild Goose or with LGS. The risk is that the storage provider may fail to perform when called upon, such as redelivering the gas to PG&E when requested to do so. There is also a risk that the gas stored with the storage provider could be lost. However, as discussed below, the storage providers should provide a measure of assurance that they can perform, but the measure should not be so large as to discourage these providers from bidding to provide the incremental storage capacity.
The risk profile that PG&E seeks to reduce its exposure to is the full value of the gas it is storing in the storage reservoir of an independent storage provider. Wild Goose and LGS assert that PG&E's risk profile is too overreaching, that the credit support amount they would have to provide is too much, that there is a cost to obtain the credit support and that the credit support will tie up capital, and that CGT will not be required to provide any credit support. LGS asserts that the credit risk should not be based on the full value of the gas stored, but rather on the risk of the difference in price if PG&E had to buy the gas from somewhere else.
We agree with Wild Goose and LGS that they should not be required to post credit support in an amount that equals the value of the gas that PG&E is storing with them. As the storage providers point out, under PG&E's credit policies, they could be required to post credit support in the millions of dollars. Obtaining credit support in this amount would tie up the storage provider's ability to raise capital for other purposes. Although PG&E is willing to accept credit support from the parent of Wild Goose or LGS, the amount that PG&E requires would tie up the parent company's ability to raise capital as well.
Wild Goose and LGS also contend that the adoption of PG&E's credit policies will have an anti-competitive effect because CGT will not be subject to PG&E's credit requirements. PG&E acknowledges that if CGT bids on the incremental storage capacity, that CGT will be deemed to be creditworthy, and it will not have to post any credit support. This clearly provides CGT with an advantage in the bidding process because it will not have to pay for the cost of obtaining credit support. The storage providers, on the other hand, will have to factor in how this cost will affect their bid for incremental storage capacity. In addition, if the storage providers have to provide credit support for the value of the gas that is being stored with them, CGT will have another advantage as well since it will not be required to do the same. Both of these effects are likely to impact the bids of Wild Goose and LGS, and are contrary to our intent in D.04-09-022 that there be "competitive provisioning of core storage." (D.04-09-022, p. 38, emphasis added.)
Based on all of the above reasons, we do not adopt PG&E's proposal to use its current credit policies, as set forth in PG&E's Rule 25, for evaluating an independent storage provider's creditworthiness for providing incremental storage capacity. Instead, as discussed below, PG&E should be directed to select an independent credit analysis agency and a third party insurance review agency, subject to the approval of each of the independent storage providers, to determine the financial strength and insurance coverage of the independent storage providers, consistent with industry standards.
Wild Goose and LGS have suggested several possibilities for developing criteria so that PG&E can assess the likelihood that Wild Goose and LGS will perform. Both of them have expressed a willingness to provide their financial information to a third party, instead of directly to PG&E, so that an assessment of the financial strength of the storage provider can be made. In this regard, PG&E's Rule 25 contains a similar provision. Section B.1. of PG&E's Rule 25 provides that:
"A creditworthiness evaluation may be conducted by an outside credit analysis agency, to be determined by PG&E, with final credit approval granted by PG&E. Credit reports will remain strictly confidential between the credit analysis agency and PG&E."
Within three weeks of the issuance of this decision, PG&E shall select an independent credit analysis agency, subject to the approval of each of the independent storage providers. The independent storage providers are to submit their financial statements to the selected agency for a determination by the credit analysis agency for a determination of financial strength consistent with industry standards.
Another criterion that could be used to assess the ability of Wild Goose and LGS to perform, and to cover potential losses, is the use of insurance. Wild Goose and LGS indicated that they were willing to provide their insurance policies to a third-party so that an assessment could be made of their insurance coverage, and to determine whether the risk situations of interest to PG&E are covered under the policies. Within three weeks of the issuance of this decision, PG&E shall select a third party insurance review agency, subject to the approval of each of the independent storage providers. The independent storage providers are to submit their insurance policies to the selected agency for a determination by the insurance review agency of whether the coverage provided is consistent with industry standards.
Another possible criterion is the use of a liquidated damages clause to cover potential losses. Wild Goose has such a provision in its existing tariff, while LGS does not. A liquidated damages provision could provide coverage for potential losses. LGS is willing to discuss including similar protections for PG&E if LGS is awarded a contract under the RFO process. A liquidated damages provision, such as the provision Wild Goose has, would provide appropriate coverage for the core in the event the storage provider fails to perform.
The storage providers also emphasized their historical performance of providing gas storage service without default. Historical performance is another criterion that should be taken into account in deciding whether a storage provider can provide the storage services. However, we recognize that performance is also tied to the financial strength of the company, which will be evaluated by the independent credit analysis agency.
The frequent use of metering could also be used by PG&E to detect the ability of the storage provider to return the gas when requested to do so. PG&E has the ability to monitor the gas flows into and out of the independent storage providers' fields. If PG&E detects a situation that threatens the gas stored for the benefit of the core, PG&E should bring this to the Commission's attention so that immediate action can be taken.
We believe that the independent credit analysis and insurance review, coupled with a liquidated damages provision and metering oversight can provide PG&E with the creditworthiness protections it seeks while encouraging the competitive provisioning of storage services and leveling the playing field with CGT. The adoption of PG&E's current credit policies for the provisioning of incremental storage capacity will not result in a level playing field.
Accordingly, PG&E shall, within three weeks of the issuance of this decision, select an independent credit analysis agency and a third party insurance review agency, subject to the approval of each of the independent storage providers, to determine the financial strength and insurance coverage protections of the storage providers consistent with industry standards.
D. Exhibit 20
Exhibit 20, the "Partial Settlement," is attached to this decision as Appendix A. Exhibit 20 addresses many of the issues identified in the scoping memo pertaining to how the process for soliciting bids for incremental storage capacity for the core will work, as well as the issues that parties raised in their prepared testimony.9
The Partial Settlement was signed by all the active parties to the proceeding. An opportunity was provided to the parties to comment on any disagreement with the Partial Settlement. No one objected to the resolution of the process and timing issues that are addressed in Exhibit 20.
PG&E's opening brief succinctly summarizes the points addressed by Exhibit 20. PG&E states:
"Exhibit 20 establishes a consensus process for a competitive solicitation to move forward. It establishes the process for PG&E, DRA and TURN to jointly develop the RFO, establish the size of the RFO, agree upon the evaluation criteria, issue the RFO, evaluate the resulting offers, and determine winning offer(s). It provides storage providers latitude in deciding what products to offer in response to the RFO and any products they wish to have PG&E, DRA and TURN consider for economic storage. It prohibits PG&E's core procurement group from providing PG&E's California Gas Transmission's (CGT) products and services group with access to information or data detailing the factors and variables to be utilized in evaluating bids. It provides for a workshop for all interested parties to discuss and propose evaluation methodologies. It provides an opportunity for losing participants to discuss the rationale for the rejection of their offers, and to receive feedback on why each was not picked. It defines the offer acceptance process. It addresses what PG&E, DRA and TURN will do if the Commission does not adopt the 1-day-in-10-year peak planning standard, or if no acceptable offers are received. It assures that if PG&E's CGT department submits the winning offer, that incremental storage amount will not be automatically subsumed into CGT's base core storage allocation." (PG&E Opening Brief, p. 5, footnotes omitted.)
A review of Exhibit 20 reveals that the following scoping memo issues would be resolved with the adoption of Exhibit 20:
· If the 1-day-in-10-year peak day standard is adopted, under what conditions will independent storage providers be allowed to compete to provide this incremental firm core storage capacity?
· What other storage services will independent storage providers be allowed to compete for and under what conditions?
· What processes should PG&E follow in determining the kind of storage proposals that should be solicited and which proposals will be acquired?
· Should storage providers submitting storage proposals be required to meet certain reliability standards or be required to maintain sufficient facilities in order to deliver gas to PG&E's core customers under all conditions without relying on PG&E?
· Should Core Transport Agents be exempt from the
1-day-in-10-year peak day standard until the Core Aggregation program load reaches 10% of the core January capacity factor? (Scoping Memo, p. 3.)10
The Partial Settlement specifically notes that the document does not agree on what credit requirements should apply to independent storage providers, and that TURN disagrees with the need to adopt PG&E's proposal for the 1-day-in-10 year peak day planning standard. Both of those issues have been discussed earlier in this decision.
In deciding whether a stipulation or settlement should be adopted by the Commission, we are guided by Rule 51.1(e) of the Commission's Rules of Practice and Procedure. That rule provides that: "The Commission will not approve stipulations or 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." Although Exhibit 20 is labeled as a "Partial Settlement," the parties' resolution of the issues in that exhibit does not resolve all of the outstanding issues in this proceeding. Since Exhibit 20 resolves many, but not all of the issues, the term "stipulation," as used in our settlement and stipulation rules, is a more appropriate reference to Exhibit 20.
The issues addressed in Exhibit 20 resolve many of the process and timing issues associated with the RFO process. The parties initially raised concerns about these kinds of issues, but the parties were able to reach a consensus and to resolve them in Exhibit 20.
During our review of Exhibit 20, we came across some passages which we believe require additional clarification.
Section B.2. of Exhibit 20 describes how PG&E will provide an officer's certificate to each independent service provider that indicates "CGT's Products and Services group does not have, and will not have access to information or data detailing the factors and variables which will be utilized by PG&E's Gas Procurement Department (in conjunction with DRA and TURN) in evaluating the received offers." This passage does not explicitly state that the bids of the independent storage providers will not be provided to CGT. However, our interpretation of this passage is that the competing bids of the independent storage providers will not be provided to CGT.
Section B.3 of Exhibit 20 describes how the "Offer Evaluation Methodology" will be developed. The process provides for a workshop, and the participation of DRA, TURN, and PG&E in the development of the evaluation methodology. In order for the Commission to have a thorough understanding of the evaluation methodology, the Commission's Energy Division should be allowed to observe all stages of the development of the evaluation methodology. This will enable the Energy Division to respond quickly when the storage contracts are submitted for approval.
In the third bullet of Section B.4 of Exhibit 20, the process for submitting the storage contract for approval is discussed. We first note that PG&E proposes to modify the preapproval process in D.04-09-022 to allow the process to apply to storage contracts of less than three years which are being acquired to meet the 1-day-in-10-year planning standard. As discussed below, PG&E's petition to modify that decision will be handled in R.04-01-025.
Our other observation of this bullet point is that the reference to the "pre-approval process for pipeline capacity set out in Decision 04-09-022" refers to the procedure set forth in Section 6.7 of D.04-09-022. In submitting a storage contract for approval under this process, the following procedures are to be followed:
"The utilities must present the Director of the ED [Energy Division] with a written request for approval of the contracts which meet the pre-approval criteria, with justification for the urgency of the transaction, the date needed for ED approval, as well as evidence of the agreement of other specified parties, as discussed below. The Director of the ED should, by the date specified, indicate approval or disapproval to the utility by letter, facsimile, or electronic mail."
In addition, PG&E's written request to the Energy Division should include a detailed description of the criteria used to evaluate the storage bid, and how the bid meets the criteria.
In the event DRA and TURN do not agree with PG&E that a storage contract should be approved, PG&E may file a regular Advice Letter requesting Commission approval of the proposed storage contract. In the alternative, PG&E may file a formal application seeking Commission approval of such a storage contract.
Subdivision (2) of the first bullet of Section B.5 of Exhibit 20 provides that PG&E may "Open direct negotiations with the storage providers to fashion an acceptable storage contract." We interpret the term "acceptable" to mean that the storage contract must still meet the "reasonable price threshold."
The second sentence of the second bullet in Section B.5 of Exhibit 20 states that "Prior to the expiration of the initial incremental storage contract(s), if it is determined that PG&E's core customers should continue to hold incremental storage capacity, PG&E will solicit the market for new storage offerings via a competitive and open process." In determining whether "core customers should continue to hold incremental storage capacity," we interpret this to mean that PG&E should consult with DRA and TURN in reaching such a determination. In order to apprise the Commission and interested parties as to the outcome of this determination, PG&E should file an advice letter in advance of the expiration of the incremental storage contract(s) describing whether core customers should continue to hold incremental storage or not and the process that PG&E will follow for soliciting new storage contracts or, if incremental storage is not needed, how it plans to meet the 1-day-in-10-year planning standard.
We conclude that the stipulations reached in Exhibit 20, as clarified by us in this decision, are reasonable in light of the record in this proceeding, consistent with the law, and in the public interest. Exhibit 20 should be adopted by the Commission, and PG&E should be directed to use Exhibit 20 in its RFO process for incremental core gas storage.
E. Request to Modify D.04-09-022
PG&E's application raised the issue of modifying the preapproval process that was approved in D.04-09-022. This issue was included as part of the scoping memo issues. PG&E requests that the Commission modify D.04-09-022, as it applies to PG&E, to allow the preapproval process to apply to storage contracts of less than three years duration and which are acquired to meet the 1-day-in-10-year peak day standard.
(See D.04-09-022, pp. 23-26.)
PG&E contends this modification is needed because storage providers have opportunity costs when they have to hold their offers open for an extended period of time. PG&E's modification of the preapproval process would allow storage contracts of less than three years to be granted in a more timely manner by a letter to the director of the Energy Division after the concurrence of DRA and TURN, as opposed to the normal advice letter filing or an expedited advice letter process. PG&E contends that the modification will minimize the period of time that storage offers will need to be held open, which should lead to lower costs for core customers.
We agree with PG&E that modifying the preapproval process to include storage contracts of less than three years will provide storage providers with more flexibility in pursuing storage opportunities. Although the scoping memo identified PG&E's request to modify the preapproval process in D.04-09-022 as an issue, we cannot modify
D.04-09-022 through this decision because this proceeding is a separate docket from the docket in which D.04-09-022 was issued in. However, we will act expeditiously on PG&E's request to modify D.04-09-022 by issuing a ruling in Rulemaking (R.) 04-01-025 shortly after the adoption of this decision. That ruling will solicit comments on whether any parties in
R.04-01-025 object to PG&E's request to modify the preapproval process in D.04-09-022 to allow storage contracts of less than three years to be approved using the expedited advice letter process. Following the receipt of any comments, we will act swiftly to resolve any concerns and to issue a decision on PG&E's request to modify the preapproval process in
D.04-09-022.
F. System Optimization
The scoping memo identified the issue of how system optimization can be achieved using storage and transmission assets. System optimization in this proceeding means achieving a balance between how much pipeline capacity the core should hold, and how much storage the core should hold.
PG&E plans to add incremental storage capacity to meet the
1-day-in-10-year planning requirement for the core because, in PG&E's experience, acquiring storage is cheaper than buying or contracting for pipeline capacity, or acquiring peaking contracts. However, if the additional storage capacity to meet the core planning requirement cannot be acquired at a reasonable price, PG&E should examine whether the incremental capacity can be met in a cost-effective manner by acquiring additional pipeline capacity and/or firm peaking supply contracts at either the city gate or the California border on a temporary basis.
Since this proceeding focuses only on incremental core storage capacity, any proposal to reduce the current holding of core pipeline capacity so that more storage can be used, is outside the scope of this proceeding. Those kinds of issues are more appropriately addressed when PG&E proposes its costs and rates for its gas transmission and storage services. According to D.04-12-050, PG&E's next filing to address those kinds of issues will occur around February 9, 2007.
G. Changes to the Incentive Mechanism
One of the issues identified in the scoping memo is whether any changes need to be made to PG&E's Core Procurement Incentive Mechanism (CPIM) to accommodate the incremental storage capacity.
PG&E contends that changes to the CPIM's pre-established benchmarks will be necessary to accurately reflect the effect of incremental storage on PG&E's core procurement activities. PG&E proposes that it negotiate with DRA, and possibly with TURN, to make the changes to the CPIM to accommodate the incremental storage capacity. PG&E proposes to modify the CPIM to include any new demand charges in the fixed price component of the CPIM benchmark. In addition, if DRA agrees, the benchmark sequencing would be modified to accommodate the operating characteristics of the acquired storage capacity. The changes would then be proposed to the Commission through the expedited advice letter process that was approved in D.04-09-022.
LGS supports PG&E's recommended changes to the CPIM. LGS also recommends that the CPIM be modified to make PG&E shareholders indifferent as to the amount of firm transportation contracts to ensure there is no bias in selecting between transportation and storage.
The modifications that PG&E proposes to the CPIM appear to be warranted as the benchmark should accommodate changes that may impact the risk and reward structure of the CPIM. The modification that LGS suggests may cause PG&E to favor selecting transportation capacity over storage capacity. PG&E and DRA are directed to discuss the modifications that PG&E and LGS suggest be made to the CPIM. PG&E and DRA may also want to involve TURN, LGS and Wild Goose in their discussions about the possible CPIM modifications. Any proposed modifications to the CPIM can be made through the expedited advice letter process as set forth in D.04-09-022, or any party may raise the proposed modifications to the CPIM in a proceeding addressing PG&E's CPIM.
3 The reliability planning standard for the core is not the same as, and is to be distinguished from physical system reliability. The core planning standard addresses the amount of gas supply PG&E is to have available to meet core demand, while physical system reliability pertains to the engineering design standard of the pipelines and related facilities that make up the transmission system. The physical system reliability of the transmission system is defined by the maximum volume of gas that can be transported over the system. According to PG&E, there is no physical system reliability constraint, and its system is adequate to meet almost any condition. In contrast, the core reliability planning standard is a function of the underlying gas market, and relates to the ability of the end user to acquire sufficient supplies to meet its demand. It is the supply reliability for the core that is at issue in this proceeding.
4 Exhibit 20 proposes that the standard not apply to Core Transport Agents (CTAs) until the CTAs' aggregate load reaches 10% of the core January capacity factor. At the present time, the CTAs serve about 2% of the core load.
5 Footnote 3 of PG&E's opening brief states that the incremental need of 100 MDth per day of storage capacity is likely to change by the time the RFO is issued, and that the actual number will be agreed upon between PG&E, DRA and TURN.
6 Under PG&E's proposal, the gas nominated from the independent storage fields would use as-available transmission capacity to reach the load center.
7 SoCalGas currently lacks the core storage rights to meet this standard. However, SoCalGas has made a core storage proposal in Rulemaking
(R.) 04-01-025 to meet this standard, which is pending before the Commission.
8 These estimates are based on inventory amounts ranging from 1,000 MDth to 5,000 MDth, and an assumed cost of $9.50 per Dth.
9 The prepared testimony of the parties was written before the parties resolved their differences in Exhibit 20.
10 The issue about the exemption of CTAs from the 1-day-in-10-year peak day planning standard for core customers is also related to the issue of whether the incremental storage costs should be paid for by core customers. The cost recovery issue has already been addressed in the section which discussed whether PG&E's proposed planning standard should be adopted or not.
