III. Discussion
A. Context
In D.98-08-030, we first identified certain goals that we would pursue in assessing the existing natural gas market structures and considering a long-term strategy for regulating the industry. We reiterated them in D.99-07-015 and repeat those goals here to provide a context for the discussion in the remainder of the decision. Our goals are:
1. To complement and enhance the benefits of electric restructuring.
2. To eliminate inappropriate cross-subsidies.
3. To guard against unnecessary barriers to the entry of competitors into various aspects of the natural gas market.
4. To mitigate competitive abuses that may occur because one firm exerts inordinate control over the functioning of the marketplace.
5. To enhance competition by providing separate rates for each major component of utility service and allowing customers to choose to have other firms substitute their services and charges where appropriate.
6. To ensure that the rates customers pay for utility services reflect the cost of those services.
7. To preserve the low-costs currently enjoyed by California natural gas customers.
8. To provide adequate consumer protection.
9. To ensure that natural gas service is safe and reliable.
In D.99-07-015, slip op. at p. 9, we identified a number of "promising options" for further investigation in our continuing revision of the regulatory structure governing California's natural gas industry, options we thought would meet the goals we set forth. These options touched on intrastate transmission, storage, balancing, hub services, core procurement including interstate capacity unbundling, information sharing, revenue cycle services, and statewide consistency. Some of these options pertained to Southern California Gas Company only, not to PG&E.
The settlement discussions undertaken within the context of the instant cost and benefit investigation resulted in D.00-02-050, in which we approved a partial settlement regarding the Operational Flow Order (OFO) protocol on the PG&E system, a subject of much discussion in R.98-01-011. The Settlement Agreement at issue here addresses all the other promising options discussed in D.99-07-015 that pertain to the PG&E system.7
B. Summary of Comprehensive Settlement
This Settlement Agreement distinguishes between promising options being put in place, those already in place on the PG&E system, those being negotiated elsewhere, and those addressed in the OFO Settlement approved in D.00-02-050. The Gas Accord, as approved by the Commission in D.97-08-055, will continue through December 31, 2002, as modified here and subject to future decisions by the California Public Utilities Commission. The summary below does not reflect all the details included in the Settlement Agreement.
Section 1, the Introduction to the Settlement Agreement, recites the purpose, parties, background for the agreement, and the parties' reservation of rights in the event of modification by the Commission. Additionally, this section allows PG&E to recover $700,000 in costs from customers/ratepayers to implement and maintain §§ 2.1, 2.2.2, 2.2.3, and 2.8 of the Settlement Agreement. This recovery will be by way of a debit from the Balancing Charge Account (BCA). The Settlement Parties expect that this recovery will be partially offset by the deposit in the BCA of a portion of certain transaction fees received from trading activities (See e.g., §§ 2.2 and 2.8, discussed below). Implementation timetables are also set forth here, including a shortened timeframe for distributing draft tariffs. Most of the Settlement Agreement is intended to run for the same term as the Gas Accord, through December 31, 2002, with some provisions on other schedules to coincide with PG&E's "storage year."
The Introduction also raises an issue resulting from AB 1421, which became effective on January 1, 2000, as §§ 328, 328.1 and 328.2. Section 328.2 could be interpreted to require PG&E to offer consolidated gas billing for gas-only core aggregators immediately, at the option of the core aggregator. PG&E's billing system is unable to accommodate such a request at this time, and the parties agree that they will interpret § 328.2 and this agreement as not requiring such an offering for gas-only customers prior to the completion of PG&E's billing system replacement project.
The Settlement Parties want the Commission to make a finding of fact that this Settlement Agreement will not substantially change the "existing core aggregation program" so that current core aggregators and those entering the market after this agreement will continue to be operating under the "existing core aggregation program" for the purposes of the statute. Thus, this section states that the Settlement Agreement is contingent on an express finding by the Commission that under AB 1421 and any other relevant law, nothing in the Settlement Agreement requires PG&E to offer consolidated gas billing for gas-only customers prior to billing system readiness. This issue is also discussed in more detail below regarding Section 2.11.
Section 2 of the Settlement Agreement addresses those promising options in D.99-07-015 that are made part of the PG&E system by this Settlement Agreement. Section 2.1 establishes cost and rate separation for balancing services, or, as it is known the self-balancing option.8 Currently, customer accounts9 are limited to a monthly imbalance of ± 5% between usage (burn) and actual supply. They pay for PG&E's balancing services in the backbone transmission rate. The self-balancing option will initiate the voluntary election of daily balancing for customers who would receive a credit for the portion of the
balancing costs being unbundled from the backbone rate.10 This section provides detailed terms and conditions for those accounts choosing self-balancing, including the possibility of returning to monthly balancing after a year. The term of this section of the Settlement Agreement extends to March 31, 2003, beyond the Gas Accord's term.
PG&E would remain the default provider of bundled balancing service for those not electing self-balancing. But up to 80% of storage assets now devoted to system balancing (2.2 Bcf) will be unbundled and marketed as part of PG&E's at-risk storage capacity, in direct proportion to the number of customers choosing the self-balancing option. Significantly, PG&E's Core Procurement Department (CPD) agrees not to elect self-balancing for the term of the Settlement Agreement.11 Additionally, total elections will not be allowed to exceed 50% of total storage balancing assets; if that limit is approached, the OFO Forum will determine how to respond. By February 1, 2001, the OFO Forum will determine whether and how the amount of storage capacity allocated to balancing service should be revised and make a recommendation to the Commission.
Under the self-balancing option, the noncompliance charge is $1 per decatherm(dth) per day for each day when the imbalance exceeds ± 10% of the daily metered burn or CPG forecasted usage,12 as well as for each day when the accumulated daily imbalance exceeds ± 1% of the preset monthly usage. These deterrence fees are recorded in the BCA, as are previously instituted OFO and Emergency Flow Order (EFO) non-compliance charges.13
Section 2.2 proposes to create a system for electronic trading of monthly gas commodity imbalances, and for OFO-day imbalance rights.14 A third-party service provider (ALTRA) will have a sole source contract until December 31, 2002, to create and maintain the trading platforms. PG&E's current method allowing customers to confirm monthly imbalance trades will remain in place. The trading of OFO-day imbalance rights is a new service not now available on PG&E's system; it creates value for those entities within the specified OFO day tolerance band but concomitantly reduces OFO noncompliance charges.
Part of the relinquished revenue from non-compliance charges will be regained through trading fees. ALTRA & PG&E will share a capped transaction fee. For OFO imbalance rights trading, the entire one half of PG&E's portion will be a credit to the BCA, to ensure that PG&E has no incentive to call OFOs. For monthly imbalance trading, one quarter of the total fee will be credited to the BCA.
The limitations and cash-out provisions in PG&E's Schedule G-BAL will apply to an entity's final ending imbalance position as posted on PG&E's existing platform. Significantly, while PG&E will be a guarantor for its customers' trades, if ALTRA allows market makers with no imbalances to participate, ALTRA must be responsible for credit approval and collection from these participants in the market.
Section 2.3 addresses the proposal that the Commission re-examine the utility role in core procurement once a 30% competitor market share has been achieved.15 The Settlement Agreement concludes that there is no need for the Commission to further examine this issue in this proceeding, in light of AB 1421.
Section 2.4, concerning whether the Commission should further reduce the thresholds for participation in the core aggregation program,16 concludes that there is no need for the Commission to change the thresholds currently applicable to PG&E customers during the term of this settlement.17 Indeed, the Settlement Parties affirmatively do not want to change the existing core aggregation program in any fundamental way, in light of the language in AB 1421.
Section 2.5 would partially unbundle core storage costs by allowing CTAs to reject increments of their storage capacity allocation voluntarily. 18 PG&E would still collect storage costs from CPD customers in bundled rates and from those CTAs choosing to accept an allocation of core storage on terms specified in tariffs to be filed and the Settlement Agreement. The unbundling of storage capacity is a phased-in program, with a cap on the total amount of storage that can be rejected by CTAs each year, beginning from the effective date of the implementing tariffs to the April 2002-March 2003 storage season. Of the rejected CTA storage allocation, the CPD must accept up to l.64 Bcf, associated injection and withdrawal allocations and the gas in the accepted storage. The maximum cost is currently estimated at a little under $2 million. (Tr. p. 52.) This will be added to the Core Procurement Incentive Mechanism (CPIM) benchmark and slightly change the withdrawal and injection amounts in the CPIM schedule. If CTAs do reject storage, costs will shift between core customer groups. Storage rejected in excess of 1.64 Bcf but only up to 4.92 Bcf (such rejection is only allowed in the later years of the term) will be allocated to PG&E's California Gas Transmission department's at-risk unbundled storage program.
Section 2.6 addresses separate costs and rates for core utility services.19 The Settlement Agreement concludes that the core brokerage fee, a proxy for the CPD's overhead and costs, should not be changed for the term of the Settlement Agreement. Other cost-based core cost allocation changes and rate design changes may be offered in future Biennial Cost Allocation Proceedings (BCAP) for distribution rates.
Section 2.7 notes the Commission's direction to provide additional details of completed transactions,20 and concludes that the terms of this Settlement Agreement and the OFO Settlement in D.00-01-020 provide sufficient information to enhance market liquidity and efficiency.
Section 2.8 creates an electronic trading system for the secondary market in intrastate pipeline capacity.21 A voluntary and anonymous system for trading firm backbone transmission capacity will be facilitated by PG&E and run by ALTRA in the same manner as the other trading platforms. One-half of PG&E's half share of transaction fees will be recorded as a credit to the BCA.
Section 2.9 acknowledges the Commission's desire to provide additional real-time customer specific usage data to customers or their agents.22 The Settlement Agreement proposes a survey of interest in dial-in access at customer expense and other meter access and automated meter reading data options. No action beyond the survey is required.
Section 2.10 contains a proposal for a pilot program for non-core customer ownership of new meters and customer ownership of meter add-on devices that would allow customers to obtain their own meter data directly.23 Customers would be responsible for any incremental costs, while PG&E would do all installation and servicing. This program will involve only 500 new meter installations per year and 1000 customer-owned add-on devices per year. PG&E will report to the Commission six months prior to the end of the pilot, recommending program expansion or termination. The pilot program will begin when implementing tariffs are effective and continue through December 31, 2002.
Section 2.11 confronts the promising option of having gas companies bill for electric service providers as well as other competitive billing possibilities.24 Currently, PG&E offers consolidated billing (billing for the CTA's gas commodity and PG&E's transportation) for dual commodity customers who also participate in electric direct access. This section provides that PG&E need not offer this consolidated service to gas service on customers until the installment of PG&E's billing system replacement project, several years away. PG&E can bill separately for its transportation service, while the CTAs bill for their commodity gas costs. The CTAs are also authorized to do consolidated billing. Moreover, PG&E would no longer be required to do information only billing to a CTA's consolidated billing customer, upon the CTA's agreement to provide PG&E's billing and information. The agreement between PG&E and a CTA would lapse if gas consumer protection legislation passes authorizing the Commission to enforce consumer protection rules including a CTA certification program, and the Commission chooses to do so. This section also contains provisions for PG&E to pay billing credits25 to CTAs that do consolidated gas billing for their customers.
Section 3 discusses the promising options identified by the Commission that are already in place on PG&E's system for the term of the Gas Accord. These include firm tradable intrastate transmission rights, the creation of a secondary market for intrastate transmission capacity, reassignment of risk to the utility for unused transmission resources, separation of the procurement and hub services functions, unbundling of interstate capacity costs for core customers, and phasing out core subscription service.
Section 4 sets forth a number of other promising options and other issues that are not to be litigated while further settlement discussions regarding the post-Gas Accord period are pending.26 These include potential reforms to the open season auction procedures,27 Gas Rule 27 issues regarding PG&E's transmission interconnection policy, terms and conditions, and local transmission and direct backbone connect issues.
Section 5 notes the realization of other promising options in D.00-01-020, such as the provision of PG&E's study of balancing needs by March 7, 2000, the implementation of targeted OFOs, and the provision of customer class data with a three-day lag.
Finally, the Settlement Agreement concludes in Section 6 that for PG&E, no issues remain to be litigated in this Investigation.
There are a number of issues raised in the Settlement Agreement that are left for resolution to the revision of tariffs or a future BCAP. We emphasize that approval of this Settlement Agreement does not indicate approval of tariffs not yet submitted for review or allocations not yet proposed. The issues for further elaboration are:
a. The allocation among customer classes of BCA funds - in the next BCAP case (Tr. pp. 4 and. 32).28
b. The details of the pilot meter program - within 60 days of settlement approval by Advice Letter (Tr. p. 9).
c. The method of dealing with oversubscription of self-balancing - by compliance filing (Tr. pp. 16-17).
d. The methodology for determining monthly usage for CPGs (baseline for measuring accumulated daily imbalance), covering both time of determination and timeframe from which to forecast, - by Advice Letter (Tr. p. 24).
e. The reevaluation of core intrastate path capacities (release of Silverado Path capacity) in relation to the acceptance of CTA storage - in the next BCAP case (Tr. pp. 56 and 58).
f. The revision of CPIM winter storage targets if CTAs release storage capacity - not clear where this would be addressed (Tr. pp. 62-63).
g. The application regarding real-time access methodology if there is sufficient customer interest (Tr. P. 47).
h. The compliance filing specifying compliance monitoring, cost responsibility, and enforcement measures.
We will order PG&E to address issues f. and g. in proceedings within the next six months so that these issues do not languish unresolved.
Thus, in sum, upon approval, this Settlement Agreement will result in the following changes:
7 Although all options are addressed, action is not initiated on each and every one. 8 This aspect of the Settlement Agreement is responsive to Finding of Fact 22 and Conclusion of Law 8 in D.99-07-015. See also, discussion in D.99-07-015, slip op. at pp. 38-40. 9 "Accounts" generally refer to a one-meter facility. A single account with multiple meters would still make one self-balancing election. 10 $0.0050 per dth x actual monthly metered usage. This is not the full amount associated with system balancing ($0.0060/dth) because self-balancers still have ± 10% daily flexibility deriving from system storage assets. (Transcript of February 24, 2000 Informational Panel, (Tr.) p. 16.) 11 However, a Core Procurement Group (CPG) may elect self-balancing, based on a forecast of customers' usage rather than daily metering. 12 CPGs use a 24 hour-before-gas-day forecast unless they are, as a group or individually, so large that PG&E requires the forecast to be made at the end of the day to ensure that it is as close as possible to the next day's actual usage. 13 OFO and EFO noncompliance charges still obtain because OFO and EFO limits supercede the ±10% daily imbalance tolerance for self-balancers. 14 This section is responsive to pages 41-44 of D.99-07-015 (slip op.) and Findings of Fact 24-26. 15 D.99-07-015, slip op. at pp. 50-59. 16 D.99-07-015, slip op. at pp. 59-61, Finding of Fact 30, Ordering Paragraph 11. 17 As part of the Gas Accord, PG&E reduced the minimum threshold for core aggregation participation from 250,000 to 120,000 therms per year. It was estimated that 20 to 25 residential customers or 7 to 8 commercial customers could meet this threshold. (Tr. pp. 50-51.) 18 This section is responsive to D.99-07-015, slip op. at p. 49. 19 This section is somewhat responsive to D.99-07-015, slip op. at pp. 49, 62, and 86. 20 D.99-07-015, slip op. at pp. 73-78, Finding of Fact 17 and Conclusion of Law 17. 21 D.99-07-015, slip op. at p. 79, Finding of Fact 38. 22 D.99-07-015, slip op. at pp. 72-73, Findings of Fact 33 and 36, Conclusions of Law 15 and 16. 23 D.99-07-015, slip op. at pp. 84-85. 24 D.99-07-015, slip op. at pp. 85-86, Finding of Fact 43, Conclusion of Law 19. 25 Residential credit =$0.71; G-NR1=$1; G-NR2=$1. This credit only goes to the CTA's customers; there is no avoided overhead component that reduces ratepayer bills generally. 26 In Section 1.51, PG&E commits to initiating talks promptly following approval of this Settlement Agreement. 27 D.99-11-053. 28 We take official notice of PG&E's application in its BCAP, filed April 3, 2000. In that application at p. 4. (Attachment B), PG&E proposes allocation on an equal-cents-per therm-basis to all end-use customers.a. The opportunity for customers other than the core served by the CPD to choose a self-balancing option in lieu of PG&E's bundled balancing.
b. The creation of a system for electronic trading of actual gas imbalances, and for the trading of imbalance rights.
c. The unbundling of core storage allocations and costs for core aggregators, allowing them to obtain different resources to ensure reliable service to their core customers.
d. The creation of an electronic trading system for secondary market pipeline capacity.
e. A survey of interest in new ways for customers or their agents to receive additional real-time usage information.
f. The creation of a pilot program for customer ownership of meters for new noncore installations, and customer ownership of meter add-on devices.
g. The delay of PG&E's consolidated billing for gas service providers, but the provision of billing credits for CTAs that perform consolidated gas billing and thus enable PG&E to avoid costs associated with preparing and sending gas bills.
