VIII. Operations and Balancing

A. Background

PG&E proposes to maintain the general structure that is currently in place for operations and balancing services. This general structure is based on the Gas Accord Settlement Agreement provisions in D.97-08-055, the subsequent Operational Flow Order (OFO) settlement adopted in D.00-02-0050, and the Comprehensive Gas OII Settlement adopted in D.00-05-049. PG&E believes that all of these provisions form a workable and efficient foundation for managing the day-to-day operations of the PG&E pipeline system.

However, based on PG&E's operating experience with these provisions, PG&E proposes to make some changes to improve existing operational procedures, and to enhance the reliability, efficiency, and management of the PG&E pipeline system. These proposals are set forth in Chapter 8 of Exhibit 1, and are summarized below.

1. Operational Overview

To operate a pipeline system, the system receipts (inflows) need to match system deliveries (outflows). This balance is needed to keep gas pressures and the resulting pipeline inventories high enough to meet the supply needs of customers, without allowing the pressures and inventories to become excessive, which can affect the safe and reliable operation of the gas system.

Under the terms and conditions of PG&E's tariffs, customers are required to deliver gas into the system that is approximately equal to their usage on a daily basis. In practice, there is rarely an exact match. Some customers may have significant under- or over-deliveries due to variations in their gas usage, uncertainty of supply, or other market-related causes. On most days, over-deliveries generally balance with the under-deliveries, which allows the pipeline to remain within normal operating limits.

On days when the overall pipeline imbalance is forecast to be outside the operating tolerances, PG&E calls OFOs or EFOs to activate specific daily balancing requirements and to impose charges for noncompliance. These flow orders, however, may not be sufficient to manage pipeline inventories under very cold, high demand conditions.

Under the Gas Accord, involuntary diversion of gas from backbone transmission shippers was designed to provide gas to core customers in the event of insufficient core supply. Involuntary diversions have not been needed since the start of the Gas Accord.

When local transmission capacity is constrained, curtailments are used to reduce or stop noncore gas usage so delivery can continue to all core customers. Local transmission capacity constraints can be caused by very cold temperatures and high demands, or by emergency outages such as pipeline breaks.

The existing tariffs have no specific financial incentive to accurately manage daily imbalances. Currently, customer imbalances and imbalance statements are calculated on a monthly basis.³⁵

There are three groups of end-user balancing entities that receive balancing service under Schedule G-BAL: CPGs; noncore customers who are part of a Noncore Balancing Aggregation Agreement (NBAA); and end-use customers without an NBAA. California producers that deliver gas to the PG&E pipeline system operate under the California Production Balancing Agreements (CPBAs), which currently have slightly different balancing rules.

Shrinkage is the result of using gas as compressor fuel, measurement errors, loss of gas due to venting for maintenance and safety, dig-ins by third parties, and leakage. Shrinkage is recovered through the delivery of in-kind gas by shippers. The Gas Accord Settlement Agreement specified the level of in-kind transportation shrinkage rates, or allowances. Experience with shrinkage led to PG&E reducing the shrinkage allowance on October 1, 2000 as requested in Advice Letter 2252-G.

2. Operations and Balancing
Under the Gas Accord

In the Gas Accord Settlement Agreement, PG&E's Core Procurement Department was no longer responsible for balancing the pipeline. Instead, all customers are responsible for balancing their own loads, i.e., matching supply and usage on a daily basis.

The Gas Accord also provided customers with balancing flexibility within operating limits. As long as the system remains within prescribed operating limits, no daily imbalance limits apply, and customer imbalances are managed on a monthly basis. Customers are also allowed to carry forward a 5% monthly imbalance, positive or negative, into the next month. If imbalances exceed this amount, the imbalance must be reduced by trading with other customers or with a storage account. After the trading period is over, carryover amounts are cashed out, i.e., balancing entities must pay the pipeline for under-deliveries or receive payment for over-deliveries under the terms of Schedule G-BAL. (See 73 CPUC2d at pp. 811-814.)

PG&E proposes six different modifications to balancing services, and six modifications to operations, which are described below.

3. Balancing Services Proposals

a. Background

PG&E's balancing services currently uses 50 MMcf/d of injection capacity to manage positive imbalances (i.e., when scheduled supply is greater than actual usage), 70 MMcf/d of withdrawal capacity to manage negative imbalances (i.e., when scheduled supply does not meet actual usage); and 2.2 Bcf of storage inventory. PG&E's first proposal is to enhance the balancing service by making five modifications, which are designed to reduce the frequency and severity of OFOs.

b. Additional Storage Capacity

The first modification is to allocate additional storage capacity to the balancing function. PG&E proposes to increase the injection capacity from 50 MMcf/d to 75 MMcf/d, the withdrawal capacity from 70 MMcf/d to 75 MMcf/d, and storage inventory capacity from 2.2 Bcf to 4 Bcf. (See Table 1.)³⁶ PG&E proposes that this additional inventory capacity be filled with 2 Bcf of gas, which would come from the proposed transfer of the non-cycle working gas as discussed earlier in the storage section.

PG&E proposes that additional storage inventory capacity be assigned to balancing because its operating experience has shown that the current storage inventory is inadequate. PG&E also cites a March 7, 2000 storage study, which indicated that allocating additional storage capacity to balancing may result in a proportionate reduction in OFO frequency.

c. Daily Imbalance Limit

PG&E's second modification to the balancing service is to establish a daily imbalance limit to the monthly balancing service requirements. PG&E states that large daily customer imbalances have been a major contributor to OFO events, especially during high pipeline inventory situations. The proposed daily imbalance limit is plus or minus 35% of daily usage, or plus or minus 30,000 Dth, whichever is larger. PG&E proposes a $0.25 per Dth excess imbalance charge for all daily imbalances that exceed the daily imbalance limit. PG&E proposes that any excess daily imbalance charge revenues be credited to the Balancing Charge Account (BCA), where they will be reallocated to all customers as determined in the Biennial Cost Allocation Proceeding (BCAP).

PG&E states that the daily imbalance limit is intended to reduce the imbalances that are created to take advantage of intra-month price arbitrage. The proposed limit is lenient enough so it would be rare for a customer who is actively attempting to manage its balancing obligations to ever exceed this limit.³⁷ The daily limit is also intended to minimize the ability of the balancing agents to take advantage of a daily market price fluctuation by delivering multiple days worth of gas on a single day. The proposal will also allow the monthly balancing service to continue for the intended purpose of managing small variations in daily loads.

PG&E states that the daily imbalance limit should not be viewed as a right of the customer to be out of balance by 35%. Customers must still exercise their best efforts to have daily gas receipts match daily gas usage.

d. Monthly Excess Imbalance Charge

Under the current rules, customers are required to balance their monthly supply and demand within a 5% tolerance band. At the end of the month, they are allowed to trade imbalances with other customers or a storage account. Imbalances up to the 5% tolerance band are carried into the next month. After the trading period ends, the pipeline uses a cash-out mechanism to purchase remaining positive imbalances outside the 5% tolerance band, and to sell gas to make up negative imbalances. When a customer elects a cash-out, the imbalance is effectively transferred to the pipeline.

PG&E's third modification to balancing is to replace the current cash-out process with an imbalance charge for monthly imbalances in excess of the tolerance band. The imbalance charge would be a market-index based charge. The entire monthly gas supply imbalance, including the quantity beyond the 5% tolerance, is then carried forward to the subsequent month. The customer is responsible for ultimately clearing its entire physical imbalance.

e. California Gas Production

PG&E's fourth modification to balancing is to apply the OFO and EFO tolerance bands and noncompliance charges to California production imbalances. Aligning the balancing requirements for California production with those of end-use customers during OFOs and EFOs will make it difficult for the parties responsible for nominating and balancing California production to exploit the current exemption from the balancing requirements.

Currently, the balancing rules for California production gas under the CPBA are different from the balancing rules for end-use customers. PG&E asserts that these differences have resulted in perverse incentives for some California production to be out of balance at critical times due to the lack of OFO or EFO noncompliance charges for California production gas.

PG&E states that the majority of California production gas is now managed either directly by end-use customers, such as electric generators, or by marketers or other agents providing gas to end-use customers. These kinds of entities are subject to flow order noncompliance charges. They have an incentive to nominate the California production supply, that is under their management, in a manner that provides a financial advantage for themselves by offsetting end-use customer imbalances to avoid OFO or EFO noncompliance charges. This behavior affects the physical imbalance on PG&E's system and creates or exacerbates OFOs and EFOs at the expense of others using the system.

PG&E points out that the data for California production gas nominations reveals that significant changes in daily nominations have occurred during OFOs, without a corresponding change in gas well production. In addition, the data shows that there is a trend of California gas production imbalances exceeding the tolerance band required by the OFO. According to PG&E, this trend significantly reduces the effectiveness of the OFOs on the system as a whole, and can result in OFOs being called on subsequent days to the detriment of other shippers. In addition, these imbalances may result in the need for receipt point capacity allocations.

f. Measuring OFO and EFO Compliance
by Core Procurement Groups

To provide the core market with more accurate benchmarks, PG&E proposes a fifth modification to balancing, which is made up of three proposals.

The first proposal is to change the timing of the forecast used for determining the CPGs' OFO and EFO compliance. Currently, the load used for calculating the compliance of a CPG with a flow order is the 24-hour forecast provided by the Core Load Forecast and Load Determination Service. This forecast is provided around 7:15 a.m. on the day before the OFO or EFO. Since noncompliance charges are based on this forecast, CPGs nominate gas supplies to match this forecast. However, relatively large core load swings can occur from day to day as temperature forecasts change. As a result, an OFO or EFO situation can be aggravated by the unavoidable inaccuracies in the day-ahead forecast.

Instead of using a day-ahead forecast, PG&E proposes that the CPGs' OFO and EFO compliance be based on the Determined Usage forecast, which is provided around 7:15 a.m. on the morning of the flow day.³⁸ The use of a same-day forecast will still allow sufficient time for the CPGs to make adjustments in their supply arrangements and nominations to avoid imbalance noncompliance charges, while taking advantage of later, more accurate usage estimates.

During very cold weather events, the financial impact of EFO compliance charges could be very large. Currently, compliance is based on the forecast of core demands. Due to the possibility that actual demands could be less than the forecast demand, the calculation of a noncompliance charge may be higher than it would be if the forecast had been accurate. To remedy this, PG&E's second proposal is that the EFO noncompliance charge for all CPGs be calculated using the lower of the Determined Usage forecast or the end-of-flow day core demand forecast. PG&E's third proposal is that the EFO noncompliance charges for CPGs be set at a higher level than for noncore customers. This will provide an additional incentive for marketers to flow gas to CPGs during an EFO.

4. Nomination Scheduling Process Proposal

The North American Energy Standards Board (NAESB) adopted "bumping"³⁹ as part of the standard nomination and scheduling process, and the FERC ordered all interstate pipelines to adopt the NAESB standards including bumping. At the time of the Gas Accord Settlement Agreement, bumping had not been widely adopted. Bumping was included as part of the Comprehensive OII Settlement for SoCalGas adopted in D.01-12-018. In D.02-08-070, the Commission noted that changing the nomination protocol to implement "bumping" was an appropriate issue to consider in this proceeding. (D.02-08-070, p. 15, fn. 7.)

PG&E's current scheduling process involves four cycles and follows the timing standards established by NAESB, but does not include bumping. There are two nomination cycles on the day before the gas flows and two nomination cycles on the gas day. Within each cycle, firm service nominations have a higher priority than as-available service nominations. Anything that is scheduled in a previous cycle is unchanged in later cycles, unless a shipper de-schedules a previous nomination.

PG&E proposes to implement the bumping process used by NAESB as part of the 2004 nomination process. An example of how the NAESB bumping process would work is set forth in Exhibit 1 at pages 8-22 to 8-23.

PG&E believes that there is merit in having consistent rules between the other intrastate pipelines and interstate pipelines regarding bumping, and it provides assurance to firm shippers that they can utilize their contracts. Due to the lead-time to implement such a proposal, PG&E expects that the computer system modifications will not be ready until approximately seven months after a decision which authorizes the implementation of bumping.

5. Supply Shortfall Proposals

a. Curtailment Process Proposal

PG&E has two proposals to modify the operating procedures during supply shortfalls. The first proposal is to replace the current involuntary diversion process in the Gas Accord with a curtailment process.

Under the current involuntary diversion process, PG&E determines whether adequate supplies have been scheduled for core customers after the first scheduling cycle for the following gas day is completed, about 9:30 a.m., the day prior to the gas flow. If scheduled supplies for core customers do not equal or exceed the forecast core demand and the pipeline cannot serve all the load, then an involuntary diversion is needed. If a diversion is called, then a special scheduling cycle is created to implement the diversions. Under the special scheduling cycle, the pipeline diverts scheduled gas from noncore customers and provides it to CPGs that have scheduled supplies less than their forecast demand.

Although the involuntary diversion process has not been used during the Gas Accord period, the process of putting the systems in place to manage diversions, and PG&E's experience with EFOs, has identified some problems with the diversion process. First, the diversion process makes it necessary to suspend all pipeline scheduling activities after the first nomination cycle. This prevents additional storage and interstate supply from being scheduled during the involuntary diversion period, which could have helped relieve the extent of the usage reduction and mitigate the financial impact on customers. Second, the diversion process requires complex computer programming to perform pro rata allocations of backbone contract nominations to determine which noncore customer's supply is being diverted. This makes it very difficult for marketers and their customers to forecast the impact of the diversion on any individual customer prior to getting the final report. And third, the involuntary diversion process requires extensive communication in a short period of time between various parties.

PG&E proposes to eliminate the diversion process, and replace it with a system curtailment process. A system curtailment event would be called in conjunction with an EFO, and would be invoked when PG&E forecasts demand to exceed supply by such a level that service to core customers is threatened and noncore load must be removed from the system. The EFO will require all customers to limit usage to their available supply. When a system imbalance continues to be forecast, and service to core customers is threatened, a curtailment will reduce the noncore usage to bring the system into balance. Since curtailments are not based on scheduled supply, the scheduling process would continue, thus assuring that additional supply from transmission and storage can be scheduled throughout the curtailment period.

PG&E proposes that when a system-wide curtailment is necessary to ensure continuous, reliable service to core customers, that the required load reduction be shared across all noncore end-use customers on a pro rata basis. Allocating the curtailment to all noncore customers lessens the impact on any one customer, and allows them to continue to receive some level of gas supply. Under an extreme situation, all noncore customer load could be curtailed.

Prior to each winter season, customers will be provided with a benchmark allowed burn level. This allowed burn level will be based on the average daily usage from the customer's peak monthly usage during a previous winter season. The level of total forecast load relief needed from the curtailment event will dictate the percentage curtailment level from the customer's benchmark allowed burn level.

PG&E proposes that those end-use customers who fail to comply with the curtailment order be assessed a curtailment noncompliance charge, as discussed later. The payment of the noncompliance charge does not relieve the customer of the duty to resolve any other imbalances. That is, customers will still be required to make up any imbalance that may result from their unauthorized usage. PG&E may also shut off gas service to any customer who fails to comply with a curtailment order.

The gas supply that is scheduled for delivery to a customer during a curtailment event will continue to be scheduled to its account, and the customer will control the disposition of this gas supply. The customer may elect to market that gas supply to other customers or retain it for future use. Customers may sell their gas supply to a CPG through either a pre-arranged agreement, or on the day of the curtailment event. Under the proposal, there is no need for any gas supply compensation.

Also, under PG&E's proposal, there would be no compensation for curtailed customers because all noncore customers receive a lower reliability of service than core customers.

Due to implementation lead time, and the desire not to make this change during the middle of the 2003-2004 winter season, PG&E proposes to implement this proposal sometime after March 2004. This will allow the curtailment process to go into effect prior to the beginning of the 2004-2005 winter season.

b. Local Curtailment Noncompliance Charge

PG&E's second proposal to address a supply shortfall is to impose a local curtailment noncompliance charge for each decatherm of usage that exceeds the maximum allowable usage quantity.

Although local capacity constraints can occur at any time due to damage to the pipeline system, they are most likely to occur under high core customer load conditions caused by very cold weather. Prior to the winter season, PG&E runs simulations and provides each noncore customer in a constrained local curtailment zone with its maximum allowable usage quantity at three stages of local curtailment.

Once PG&E identifies that the temperature forecast in a local area is low enough, such that the local transmission zone will be constrained, PG&E will notify customers of the local curtailment stage beginning at 2:00 p.m., for curtailments needed for the next usage day starting at midnight. PG&E does not compensate curtailed customers during a local curtailment.

The existing local curtailment process, described above, will remain unchanged. However, PG&E proposes that there be a local curtailment noncompliance charge of $50 plus the Daily Citygate Index (DCI) price for each decatherm of usage that exceeds the maximum allowable usage quantity. Currently, there is no local curtailment noncompliance charge in the existing tariffs.

The payment of the noncompliance charge does not relieve the customer of the duty to resolve any imbalances, and the customer will be required to make up any imbalance that may result from their unauthorized usage. If there is an EFO or OFO in effect at the time of the local curtailment, the customer will also be subject to any EFO or OFO noncompliance charges. Any noncompliance charge revenue that results from a failure to comply with a curtailment order will be recorded in the BCA.

6. Shrinkage Proposals

a. Adjustment of Shrinkage Proposal

Shrinkage measures the difference between the gas that is received into the system and the quantity that is delivered to customers. Shrinkage is composed of: (1) lost and unaccounted for gas supplies (LUAF) and (2) PG&E's gas department usage (GDU) which includes compressor fuel. LUAF occurs for a number of reasons including: metering error, un-metered gas for operations, gas blown to the atmosphere to facilitate maintenance, and leakage. GDU is metered gas to fuel gas-driven compressors, gas processing equipment, and other gas facilities. Shippers on the pipeline are required to bring enough gas into the system to cover their customers' metered gas use plus an amount of shrinkage gas to cover the LUAF and GDU.

Under the Gas Accord structure, shrinkage gas is collected from transmission and distribution transportation volumes. This includes shrinkage related to gas used in the operation of PG&E's storage fields.

Due to the shrinkage over-collection following the adoption of the Gas Accord, PG&E requested and received permission to reduce its shrinkage allowances in August 2000. Presently, the shrinkage allowances are updated every two years or longer, depending on the regulatory schedule of the BCAP. However, changes in system operations that occur within the BCAP period may change the actual shrinkage that is experienced on PG&E's system.

PG&E proposes that for 2004, a process be adopted to update the shrinkage allowances on an annual basis. If changes to the shrinkage allowance are needed, PG&E proposes that this be accomplished through a compliance filing to be effective on the first day of each calendar year. The shrinkage allowances will be based on the adopted BCAP throughput forecast and the actual shrinkage experienced on PG&E's system. Table 8-5 of Exhibit 1 contains PG&E's illustrative 2004 shrinkage allowances, which are based on PG&E's forecasted demand, and recent actual transmission and distribution LUAF and GDU. PG&E proposes that these shrinkage allowances be updated through its proposed compliance filing using the actual LUAF and GDU figures available in December 2003.

PG&E also proposes that it be allowed to make a separate advice letter filing at other times of the year to adjust shrinkage allowances in order to better match the actual shrinkage experienced on the system.

PG&E proposes that the BCAP continue to be the proceeding in which to determine the pipeline shrinkage calculation methodology, including the proportion of LUAF and GDU that are assigned to transmission and distribution shrinkage.

b. Storage Shrinkage Proposal

PG&E proposes that a new in-kind storage shrinkage allowance be applied to all scheduled storage injection volumes. This allowance will collect from storage customers, the cost of GDU and LUAF that is associated with PG&E's gas storage operations. PG&E also proposes to continue the recovery of a portion of the cost of electricity used by PG&E's gas department in operating its storage field in storage rates, as done in the Gas Accord. PG&E's gas storage shrinkage costs are currently recovered through the transportation in-kind shrinkage allowances. If PG&E's proposal is adopted, the gas storage shrinkage costs will be excluded from the transmission and distribution in-kind shrinkage allowances.

The in-kind shrinkage quantity for storage would be calculated by dividing the total storage-related GDU and LUAF by the forecast annual storage-cycle quantity. The resulting in-kind shrinkage percentage would be taken in-kind from the storage injection nominations to determine the net-injection quantity that will be credited to that storage customer's inventory. PG&E calculates the in-kind shrinkage allowance for storage injections is 0.7% of the injection quantity.

PG&E has proposed that its balancing service be allocated 4 Bcf of the total storage cycle inventory. The storage shrinkage quantity allocated to the 4 Bcf for balancing service will be reallocated back to the transmission and distribution shrinkage quantities as additional GDU.

PG&E proposes that the storage shrinkage allowance implementation be scheduled to coincide with the April 1, 2004 start of the storage season. PG&E also proposes that annual updates to the storage shrinkage allowance, if needed, be done through a compliance filing to be effective at the beginning of each storage season.

7. Noncompliance Charge Proposal

PG&E points out that the gas price volatility experienced during the 2000-2001 winter season provided evidence that fixed noncompliance charges that are not indexed to the market price of gas, may be an ineffective tool to achieve the desired results when an OFO or EFO is called. A situation could occur where a balancing entity may find it more economic to incur a noncompliance charge than to comply with a flow order or curtailment.

PG&E proposes that most noncompliance charges be modified to include a cost of gas component. Table 8-6 at page 8-37 of Exhibit 1 shows the schedule of proposed noncompliance charges for core and noncore. Table 8-6 lists three gas indexes which the noncompliance charges use. The three indexes are the Monthly Citygate Index, the Daily Citygate Index, and the Lowest Citygate Index. These three indexes are described at pages 8-35 and 8-36 of Exhibit 1.

PG&E proposes that all of the noncompliance charges shown on Table 8-6 of Exhibit 1 continue to be recorded into the BCA. The balance in the BCA would then allocated as determined in the BCAP.

8. Anonymous Trading Platform Proposal

In the Gas OII Settlement Agreement, which was approved in D.00-05-049, the parties agreed to a third party electronic trading platform to facilitate anonymous trading of imbalances and backbone capacity contracts. D.00-05-049 also authorized an implementation cost of $700,000 for these services, which was debited to the BCA. (See D.00-05-049, p. 29, FOF 9.)

PG&E had extensive discussions with the selected third party service provider to provide the trading platform. However, the provider decided not to go forward with the project due to a number of issues that arose, and a contract with PG&E was never finalized. Although PG&E held talks with other potential vendors, none of them were willing to develop an anonymous trading system that met PG&E's current trading requirements.

PG&E notified customers and the settlement parties in September 2000 that the selected vendor would not be developing the trading platform, and that the services would be delayed. PG&E also investigated building its own trading platform, but the costs associated with its development and the relatively small volume of transactions make the trading platform too expensive. None of the customers or settlement parties have inquired about the status of the trading platform or requested that these services be implemented in an alternative manner.

PG&E proposes that the third party electronic trading platform and services be eliminated. PG&E proposes to credit back $656,000 to the BCA, which is the unspent portion of the $700,000 that was approved in D.00-05-049 for this project.

PG&E notes that the elimination of this anonymous trading platform and services will not impact the operations of other existing trading vehicles, even though those trading vehicles require that each party identify its trading partner.

B. Positions of the Parties

1. CCC/Calpine

a. Curtailment Proposal

CCC/Calpine agree with CMTA that PG&E's curtailment proposal should be rejected because it is contrary to the structure of the Gas Accord, would absolve PG&E of the responsibility of wisely managing its transportation, storage capacity and gas procurement, and would provide PG&E with an incentive to curtail. As CMTA points out, curtailment serves as a cheap and effective means of using noncore gas supplies to serve core customers without having to pay a diversion penalty directly to noncore customers.

Should the Commission be leaning toward adopting PG&E's curtailment proposal, CCC/Calpine urge that the Commission postpone making a final decision until workshops are held with customers to further consider the proposal's justifications and potential impact. As NCGC points out, workshops are needed because PG&E's proposal does not explain various critical details about how the proposed pro rata curtailment would be administered, including which winter season would be used to calculate a benchmark allowed burn level for customers prior to each winter season. Customers cannot ascertain the impact of PG&E's proposal unless and until PG&E provides the important details of its proposal. PG&E has expressed a willingness to work out implementation details in a workshop.

Should the Commission decide to hold workshops regarding the viability of PG&E's curtailment proposal, CCC/Calpine urge the Commission to require PG&E to explain why the proposals of the Indicated Producers to modify PG&E's curtailment proposal should not be adopted.

b. Daily Imbalance Proposal

PG&E proposes adding a daily imbalance tolerance limit to its monthly balancing service option in order to discourage the large daily imbalances that are occasionally created by a few balancing entities on the system. CCC/Calpine assert that PG&E has not justified this proposal. PG&E has not presented evidence that it has tried less drastic measures to reduce customer specific OFOs on its system. CCC/Calpine agree with Duke that PG&E should be required to attempt less punitive and more narrowly tailored measures before resorting to a daily imbalance penalty that could result in non-offending shippers being penalized.

2. CMTA

CMTA opposes PG&E's proposal to replace the diversion process with PG&E's proposed curtailment mechanism. CMTA contends that PG&E's proposal is contrary to the structure of the Gas Accord, that it would free PG&E from the responsibility of wisely managing its transportation and storage capacity and gas procurement, and would provide PG&E with an incentive to curtail. CMTA asserts that if PG&E's Core Procurement Department fails to buy enough gas to meet its core needs, the curtailment procedure provides a cheap and effective means of using noncore gas supplies to serve core customers without having to pay a diversion penalty directly to noncore customers.

PG&E's curtailment proposal would not compensate customers for curtailed volumes, instead, it would allow the customer to control the disposition of its gas supply. CMTA contends that because the amount of curtailed supplies available to sell may be small and the notice likely to be short, it is unlikely that the curtailed customer could sell the curtailed supply at a fair price. CMTA asserts that a curtailment would create a buyer's market of noncore supply for core suppliers and buyers. Whereas under the current diversion process, PG&E pays customers if their gas is diverted. PG&E's curtailment proposal would eliminate any such compensation.

PG&E has suggested that curtailed customers could run a positive imbalance to offset future use. This would allow PG&E to receive the high volume of the customer's positive imbalance on that day, and return the gas on a future day when gas prices are likely to be lower. CMTA contends that because the effect of PG&E's proposal is to lower the cost of obtaining core gas supplies during peak demand days, PG&E's proposal could provide it with an incentive to curtail more frequently.

CMTA also points out that because the curtailed customer could be forced to run a positive imbalance on a day when prices are high, and have PG&E return the gas at a price that is low, that this could be a windfall to core customers, because they would receive the higher valued gas and return lower valued gas.

Under the current diversion process, PG&E's Core Procurement Department is required to maximize its efforts before resorting to diversion of noncore customers. Although such efforts have not been included in PG&E's curtailment proposal, PG&E witness Johnson indicated that he expected that a similar requirement would be added. In the event the Commission adopts PG&E's curtailment proposal, CMTA recommends that such a requirement be added.

In addition, if the curtailment proposal is adopted, CMTA recommends that the proposal be modified to ensure that noncore customers are fairly compensated for their curtailed supplies that are delivered into the system, and that the incentives for PG&E to curtail be eliminated. CMTA recommends that noncore customers be compensated at a rate equal to the daily gas index price plus $10 per Dth. Such compensation would ensure that curtailments are a last-resort source of core supplies. Also, the curtailment process should allow noncore customers to trade curtailment levels among themselves, provided that the aggregate amount of curtailments is not reduced.

PG&E opposes the proposal for a rate equal to the daily gas index price plus $10 per Dth because it would be a windfall to curtailed noncore customers. CMTA asserts that the $10 per Dth payment would not be a windfall, but rather would represent compensation for noncore customers who have lost the benefit of their contracted for supplies, and who may be forced to shut down their manufacturing operations. Nor would it be sufficient compensation to pay curtailed customers the amount of the daily price index.

CCC/Calpine witness Beach recommended allowing noncore customers in any curtailment process to trade curtailment levels among themselves, provided that, the aggregate amount of curtailments is not reduced. PG&E stated it is willing to explore such an idea in a workshop setting, and CMTA would welcome such an opportunity. If the Commission adopts a curtailment process for noncore customers, the process should include this modification.

PG&E asserts that its Core Procurement Department has an incentive to have gas under contract because the failure to deliver adequate supply would cause the Core Procurement Department to face a noncompliance charge of market price plus $60. CMTA asserts that $60 EFO charge comes too late in the process to act as an incentive to avoid curtailment, and can easily be mitigated depending on the subsequent allocation of EFO charge revenues.

CMTA also asserts that PG&E's curtailment proposal would cut firm customers equally with as-available customers, which is unfair to firm customers and inconsistent with the Gas Accord structure. CMTA contends that the pro-rata curtailment would not treat firm and as-available equally because firm and as-available customers do not, and should not, have equal expectations of deliverability. That is, customers take firm service for its greater assurance of delivery, and as-available customers trade firm delivery for a lower price. PG&E's proposal undermines these preferences by curtailing firm customers equally with as-available customers. This is less fair than the current diversion process, which allocates a diversion so that as-available customers are diverted before firm customers.

One of PG&E's concern over the current diversion process is about the efficiency of communications under the diversion process. CMTA points out, however, that experience shows that marketers and end-use customers have regular, well-developed lines of communications and typically communicate on a daily basis.

3. California Natural Gas Producers Association

The California Natural Gas Producers Association (CNGPA) is opposed to PG&E's proposal regarding the gas balancing rules. CNGPA asserts that California gas production provides unique flexibility to the PG&E system over other sources of PG&E supply. This flexibility is due in part to the proximity of California gas to the PG&E system and the markets that actually consume the gas. CNGPA asserts that California gas aids in the physical management of PG&E's system by following PG&E's load patterns.

CNGPA points out that according to the 2003 California Gas Report, California in-state gas production accounts for only 7.4% (or 147 MMcfd) of PG&E's total pipeline system supply of 1987 MMcfd. PG&E, however, alleges that California production is responsible for large gas imbalances on the entire PG&E system during OFOs. PG&E also accuses CBPA managers of potential profit taking by marketing nomination flexibility during OFO periods.

PG&E proposes that California gas production imbalances, managed through a CBPA, be subject to the same OFO requirements and noncompliance charges applicable to all other balancing entities. CNGPA is opposed to this proposal, and contends that PG&E's proposal is a significant threat to California gas production.

CNGPA points out that on an average day, PG&E's customers consume nearly 2000 MMcf of gas, with less than 10% derived from California in-state supply. The remaining 1800 MMcfd or more enters the state at the border delivery points. While the pipeline companies and PG&E target delivery quantities into PG&E, based on scheduling by shippers and marketers, physical imbalances always exist at those border delivery points. The existence of these imbalances is primarily due to the complex nature of large-volume deliveries and the cyclical customer loads on the PG&E system. CNGPA asserts that this large scale variance should be investigated by PG&E and the Commission, rather than unfairly discriminating against California production that represents such a small part of the customer requirements on the PG&E network.

CNGPA points out that CPBAs do not have access to real-time operating and balancing data on the PG&E system, like PG&E's other gas supply sources and even their end-use customers. The data that PG&E provides to CPBAs is received by the 15th day of the month following the month that the gas was produced and delivered into the PG&E system. CNGPA asserts that this lack of data makes it virtually impossible to adequately balance the physical flows of gas with nomination commitments. Although electronic flow measurement has been installed by PG&E at the delivery points of California production, the CPBAs have been denied remote access to this EFM data. Without accurate data, it is impossible for PG&E and the CPBA to talk and make operational adjustments as needed to maintain the balance between nominations and actual deliveries. CNGPA asserts that California gas should not be singled out as the prime cause for OFO imbalances when 92.6% of PG&E's supply comes from out of the state.

CNGPA asserts that PG&E's proposal contains elements that are significantly detrimental to California produced natural gas, particularly as it sets forth to establish strict CPBA balancing guidelines. Since § 785 (a) mandates that the Commission shall encourage the increased production of gas in this state, PG&E's proposal will discourage any increase of in-state production, and have a negative impact on remaining gas reserves. Also, § 785.2 provides that the Commission is to investigate, as part of the rate proceeding for any gas corporation, impediments to the in-state production or storage of natural gas. CNGPA believes that PG&E's proposal would be adverse to the interest of gas customers by potentially forcing Californians to rely more on natural gas from outside of the state, and removing tax revenues derived from California production that presently flow to the state and local governments. The Commission should uphold state law, and remove PG&E's proposed balancing guidelines from the proposal.

To accommodate the cycles of customer demand on the PG&E pipeline network, PG&E regularly changes flow patterns and raises and lowers pipeline pressures. As a result, California production flows may be physically curtailed due to higher pipeline pressures or altered flow patterns on the PG&E system. Oftentimes CPBAs only become aware of these inadvertent flow reductions after the fact, providing no time for changing downstream market nominations. This results in an imbalance between the nominated and actual flows that was actually caused by PG&E. Currently, the CPBA balancing partially contemplates these imbalances by allowing the CPBA to resolve the imbalance within the producing month or during the month following. Under PG&E's proposal, this flexibility will be eliminated forcing the CPBA to carry imbalances into a potential cash-out with PG&E at a future date. PG&E's cash-out mechanism pays only 50% of the value of over-deliveries, and charges 150% if PG&E provides gas to balance deficient deliveries by the producer.

CNGPA contends that due to the unreliability associated with PG&E curtailment of flows from time to time, it is difficult for producers and CPBAs to commit to reliable monthly markets. The current balancing structure provides some flexibility to manage fluctuations on PG&E's system. With the adoption of PG&E's proposed CPBA balancing changes, this situation would be exacerbated, forcing California producers into daily pricing for their gas production. CNGPA asserts that daily pricing is often volatile, and unsettling to the producer and mineral interest owner, potentially removing the incentive to drill new wells to meet the growing market demand.

4. Coalinga

Coalinga contends that PG&E has failed to establish that PG&E's proposals for a daily imbalance penalty, and to increase the storage allocation to balancing, are needed at the present time. Coalinga recommends that the Commission reject these proposals.

5. DGS

PG&E proposes various modifications to its rules relating to management of the supply shortfall and capacity constraints. One modification is to replace the existing diversion process with a curtailment process. PG&E proposes that when a curtailment occurs, that the required load reduction be shared across all noncore end-use customers on a pro-rata basis. DGS supports PG&E's proposal, and recommends that the Commission make the necessary findings in order to confirm that this priority system for curtailment complies with § 2779 and following.

6. Duke

PG&E proposes five different measures to manage system imbalances and to reduce the number of OFOs, the procedure adopted in the Gas Accord to maintain the overall system balance. Among the five measures is a proposal to implement a new daily balancing requirement. This daily balancing requirement would require customers to stay within a limit of plus or minus 35% of daily usage, or plus or minus 30,000 Dth, whichever is larger. Customers who fall outside of this permitted band would be subject to a charge of 25 cents/Dth.

Duke recommends that the Commission reject the proposed daily balancing requirement. One reason for rejecting the imbalance proposal is that it may penalize customers who do not contribute to system imbalances. Under PG&E's proposal, the daily balancing penalties would be imposed whenever an individual customer's imbalance exceeded the specified range, even is there is no system problem that day. Duke contends that a proposal that imposes penalties when no harm results does not make sense and should be rejected.

Another reason for rejecting PG&E's daily balancing proposal is because of the harmful effect on electric generation customers. Duke points out that electric generators are among the largest of PG&E's gas customers. Electric generators are subject to highly variable electricity demand, and their gas consumption and transportation scheduling cannot be predicted with much confidence. Also, electric generators are subject to orders from the CAISO to increase or decrease generation. For these electric generators, the proposed daily balancing penalty will not serve to influence behavior, instead, it will only function as an unnecessary penalty serving no useful purpose.

Duke believes that before a daily balancing requirement is imposed, that PG&E's four other proposals to improve the ability to balance the system should be given a chance to see effective they are before imposing the strict daily balancing requirement, which subjects customers to harsh penalties even when the overall system is in balance.

7. Indicated Producers

One of PG&E's proposals is to replace the existing involuntary diversion procedures with a pro-rata curtailment of all noncore customers. The Indicated Producers point out that service level distinctions have played a role in PG&E's transportation services for over ten years. In D.91-11-025, the Commission eliminated the curtailment priority scheme based on end-use, and replaced it with a method based on a customer's decision to purchase firm or interruptible service. The same principles were continued in D.97-08-055, and incorporated into the Gas Accord. The firm and interruptible service levels were integrated into PG&E's procedures for involuntary diversions. Involuntary diversions recognize that the utility should provide the greatest protection to those customers who have expressly placed a value on service reliability through the acquisition of firm service.

The Indicated Producers state that PG&E's proposal would eliminate the material benefit of choosing firm transportation service. They question what the benefits of firm service will be, if there is no higher level of reliability during times of constraint or supply curtailment. The proposed pro rata curtailment would remove customer choice and service level distinctions by determining that all customers should be treated equally.

If the Commission adopts the proposal for a curtailment process, the Indicated Producers believe that it should be modified to reflect several features of the current diversion process. First, the curtailment process should distinguish among service types, with interruptible service curtailed before firm service. Second, the curtailment procedures should retain the same kind of obligation found in Gas Rule 14 that market remedies be sought before curtailment of noncore customers begin. And third, that a curtailment penalty should apply to prevent the use of a curtailment by PG&E's Core Procurement Department to reduce core costs when prices are high, and to recognize the impact of curtailments on noncore customer operations.

In addition, if the curtailment proposal is adopted, the curtailment procedures should also require the following: (1) that PG&E seek to purchase additional gas supplies at prices which are regarded as reasonable and prudent; (2) that PG&E curtail deliveries to any customer in excess of volumes allowed under contract; (3) that PG&E make a public service announcement for voluntary actions by suppliers and end-use customers; and (4) that PG&E ask customers to voluntarily reduce use and/or increase deliveries, depending on the nature of the situation which results in an EFO. Unless these market remedies are made part of PG&E's noncore curtailment procedures, the Indicated Producers contend that the curtailment procedure would reduce the incentives of CPGs to pursue market remedies that could mitigate the need for a curtailment.

Under the existing Gas Rule 14, if an involuntary diversion occurs, customers who use more gas during an involuntary diversion than their post-diverted supply will be assessed a $50 per Dth diversion usage charge, and a $50 per Dth EFO noncompliance charge, for a total involuntary diversion charge of $100 per Dth. Firm transmission customers whose gas supply is involuntarily diverted receive a $50 per Dth diversion credit. As-available transmission customers receive a diversion credit based on the market price for the gas on the day the diversion occurred.

Under PG&E's proposal, there is no gas supply compensation. Instead, the CPGs are required to buy supply to meet their customer demand or be subject to an EFO noncompliance charge equal to $60 per Dth, plus the daily citygate indexed price of gas. PG&E believes that this will act as an incentive for the CPGs to buy the gas at the market price from those marketers and noncore end-users who have been curtailed. The Indicated Producers, however, believe that noncore customers are worse off than under the existing involuntary diversion rules because they are likely to receive less under PG&E's proposal.

The Indicated Producers recommend that an appropriate curtailment penalty apply to PG&E's proposal to prevent the use of curtailment by PG&E's Core Procurement Group as an economic tool to reduce core costs when prices are high, and to compensate noncore customers for the impact of a curtailment event on their operations. PG&E's CPG should be required to purchase from noncore end-use customers, any positive imbalances that noncore customers run during a curtailment period. This would compensate a noncore customer for any supplies above the level of its curtailed demand that are still delivered into the system, which help meets core needs. The Indicated Producers support the CCC's proposal that the price for these supplies be the daily gas index price plus $10 per Dth, in order to ensure that curtailments are a last-resort source of core supplies.

The Indicated Producers also recommend that if a curtailment process is approved by the Commission, a workshop or working group should be required to develop specific procedures for implementing curtailments, and that such procedures be approved by the Commission.

PG&E has also proposed to modify the existing balancing framework to reduce the number of OFOs and EFOs. The proposed modifications include assigning additional storage capacity to balancing service, and adding a wide daily imbalance limit to the monthly balancing service requirements. The new imbalance limit would be plus or minus 35% of daily usage or plus or minus 30,000 Dth, whichever is larger.

The Indicated Producers assert that PG&E has failed to substantiate that either of these modifications are needed, or that these measures will actually reduce OFOs. The Indicated Producers point out that many changes have occurred in the market since PG&E's analysis of the data was first done. By dedicating more storage to balancing, the Indicated Producers contend that this will increase costs to customers and reduce PG&E's risk of revenue under-recovery from at-risk storage. If the Commission adopts PG&E's proposal to add more storage capacity to balancing, it should do so on a provisional basis. If the OFO reduction does not occur as anticipated, the additional storage reservation should be returned to the at-risk storage services.

The objective behind PG&E's proposal to impose a 35% daily imbalance limit is to reduce imbalances and the number of OFOs. The Indicated Producers do not believe that this proposal has been carefully studied, and is likely to increase the cost to noncore customers. The Indicated Producers recommend that PG&E's balancing proposal be rejected, or modified to allow the increased storage reservation to be implemented on a provisional basis, but that it be returned to existing levels if it fails to produce the anticipated reduction in OFOs. They also recommend that PG&E's proposal for a 35% daily imbalance limit be deferred until PG&E determines the effectiveness of the increased storage reservation.

8. LGS

PG&E justifies the proposed increase of storage capacity for balancing by referring to the occurrence of OFOs and a March 7, 2000 storage study, which PG&E neither included nor excerpted in its testimony. LGS is concerned that PG&E's proposal will allow PG&E to transfer its currently at-risk storage in a fashion that ignores existing storage competition and that will ultimately be anti-competitive.

PG&E's proposal was based on customer feedback. According to PG&E witness Johnson, customers expressed support for actions to limit the number of OFOs, including additional storage capacity. Johnson, however, kept no written record of this, and no specific customers were identified. Also, the conversations with customers about the OFO issues which led to this proposal, concern how the system operates today, not how it would operate if the proposals are adopted. LGS contends that PG&E's assertions regarding customer feedback are unpersuasive, given the lack of proof of the existence, nature, and volume of such feedback, and the identity of the customers providing such feedback.

LGS asserts that PG&E has provided no comprehensive analysis in the form of a cost-benefit study or any other study that suggests the Commission should allow PG&E-owned storage to be reassigned from market storage to balancing.

PG&E's second basis for the proposal is recent experience. However, PG&E's testimony provided no details regarding this recent experience. During cross-examination, PG&E witness Johnson admitted that recent experience references OFOs occurring after the March 2000 storage study. (6 RT 571) PG&E has not identified no other recent experiences supporting its proposal to dramatically increase storage dedicated to balancing.

The other basis for PG&E's proposal is Figure 8-1 on page 8-11 of Exhibit 1. Through cross-examination, it was learned that Figure 8-1 had its origins in an update of the March 2000 storage study. (6 RT 552-553; Ex. 18.) But the March 2000 study was not provided as part of PG&E's testimony. Also, Figure 8-1 is a prediction looking back at what happened, and what PG&E thinks would have happened with respect to OFOs with additional storage injection capability. (6 RT 550, 571-572.) The differing amounts of injection and withdrawal reflected in Exhibit 18 are just assumptions made for the purpose of the study. (6 RT 572-573.)

LGS also contends that PG&E has not considered whether adopting the other measures proposed by PG&E would meet the goal of reducing the number of OFOs. LGS witness Dill testified that it is not clear that this increased storage allocation is really necessary. Dill noted that PG&E proposes to make two other adjustments to make customers more responsible for their own balancing requirements: establishing a daily imbalance limit for the monthly balancing option, and changing the disposition of monthly imbalances after the imbalance trading period. PG&E also proposes to require California production to comply with the same OFO obligations as other balancing entities.

LGS suggests that before adding more storage for balancing, it should be determined whether these three other measures will meet the goal of reducing the number of OFOs. LGS asserts that these three proposals create the imbalances that are a major cause of the OFOs. This is supported by the OFO reports attached as Appendix 8-A to PG&E's rebuttal testimony where PG&E observes that the ineffectiveness of customer-specific OFOs has led PG&E to call system-wide OFOs during high-inventory condition, even when the customer-specific criteria were met. PG&E also references the negative system impact of California production imbalances. LGS asserts that the impact of PG&E's balancing proposals should be measured first, before adding storage capacity.

LGS also asserts that PG&E presented neither evidence nor analysis concerning the positive effect of PG&E's other proposals. Although PG&E contends that these proposals will work to diminish the OFOs, PG&E has made no showing as to whether those proposals would achieve a lower incidence of OFOs without also resorting to additional storage capacity for balancing.

LGS witness Dill raised concerns about the lack of detailed evidence to support PG&E's proposals, and that it is an effort by PG&E to market its storage in a non-competitive manner. Even if an increase in storage capacity is justified for balancing purposes, LGS states it can probably be met more cost effectively by LGS, Wild Goose, a combination of both, or through some other sort of portfolio approach.

LGS witness Dill also stated that LGS does not believe that balancing entities should have any obligation to use PG&E's balancing service. Such entities should be free to seek competitive provisioning of such storage service from all storage providers. Also, rolling in additional balancing resources creates costs for all PG&E customers whether they need those services or not.

LGS was not alone in criticizing PG&E's proposal. Wild Goose's witness stated that PG&E's proposal could potentially disadvantage PG&E ratepayers. The witness also expressed concern that, without further analysis, the possibility exists that PG&E is merely seeking a means by which to recover the costs of its excess storage without subjecting it to market forces. He also suggested that if the need for additional balancing could be demonstrated, it should be put out to bid.

The Commission should disapprove PG&E's proposal to add storage. If PG&E believes that additional storage is needed, PG&E should present a proper and detailed cost benefit analysis to the Commission.

In the event the Commission decides that a need exists to add storage to the balancing function, the Commission should not approve the proposal that the automatic source of such storage is PG&E resources. There are competitive storage providers in PG&E's service area, and it is possible that they could lower the cost of the additional storage that is assigned to the balancing function. Thus, if the Commission determines that more storage would assist in balancing PG&E's system, it should also require PG&E to seek bids to provide that storage.

PG&E has not provided any technical explanation as to why third party storage cannot be used to balance PG&E's system. PG&E's witness agreed that storage can be used to help keep the system in balance. (6 RT 580.) As Wild Goose observed in its opening brief, if storage is connected to the pipeline system, it can assist in balancing regardless of who owns it.

LGS has not taken a position on whether PG&E's current diversion system to address scarce gas supply should be replaced with a curtailment system as proposed by PG&E. However, if PG&E's curtailment proposal is adopted, LGS agrees with Wild Goose that customers who stored gas should be allowed to withdraw the gas in the event of curtailment. As Wild Goose points out, not allowing noncore customers with stored gas to access that gas during curtailments will provide a disincentive to store gas. That is, why should a customer buy gas and pay to store it, when you are not allowed to withdraw and maintain ownership of it precisely when you need it. If the Commission approves PG&E's curtailment proposal, it should require PG&E to allow customers with gas in storage to withdraw that gas during times of curtailment.

PG&E asserts that the daily imbalance limit is needed to discourage extremely large daily imbalances that occasionally are created by a few balancing entities on its system. PG&E proposes a limit of the larger of either plus or minus 35% of daily usage, or plus or minus 30,000 Dth, with an excess daily imbalance charge of $0.25 per Dth proposed as an incentive to stay within the limit. According to PG&E, its proposal would affect only about 2% of daily imbalances, but would be adequate to eliminate very large imbalances that disrupt system operations.

Mirant appreciates the problems such imbalances can impose on system operations, but remains troubled by PG&E's proposal. Mirant states that Wild Goose is probably correct that given the volatility of gas prices, PG&E's proposed penalty amount will be insufficient to affect shipper's behavior very much. Duke and NCGC are correct that PG&E's proposal would penalize individual customers' imbalances regardless of their system impacts. Mirant contends that instead of bringing the gas system into balance, PG&E's plan would impose cost burdens on some customers, regardless of whether their particular imbalances exacerbated or alleviated the imbalance. Increasing the level or incidence of penalties, as Wild Goose suggests, might make the plan more effective, but it would not target the pain any more efficiently on those imbalances that may impair system operations.

Mirant also notes that PG&E said that if its proposal proves ineffective, that the issue can be revisited using the OFO Forum process. Mirant contends that this comment validates the suggestions of Duke and the Indicated Producers that the Commission should see how effective the other PG&E proposals are before imposing such a penalty. As NCGC stated, a more focused OFO process offers a fairer and probably more effective way of targeting those who cause large daily imbalances on PG&E's system.

Mirant opposes the imposition of any daily imbalance penalty scheme at this time.

9. NCGC

PG&E proposes to increase the amount of storage capacity that it would assign to provide system-balancing services by reassigning existing capacity to the balancing function. PG&E proposes to increase the amount of assigned injection capacity by 25 MMcf/d to 75 MMcf/d. PG&E also proposes to increase assigned withdrawal capacity to 75 MMcf/d, and to increase assigned inventory capacity to 4 Bcf.

The total cost for system balancing service would be $10.523 million. Of this amount $4.7 million would be for 75 MMcf/d of injection capacity, $0.7 million for 4 Bcf of inventory capacity, and $5.1 million for 75 MMcf/d of withdrawal capacity.

NCGC supports PG&E's proposed increase in storage capacity that is to be assigned for system balancing. PG&E's March 7, 2000 study concluded that allocating additional storage capacity to balancing may result in a proportionate reduction in the frequency of OFOs. OFOs affect all customers, including PG&E's Core Procurement Department. In addition, reassigning existing capacity to expand balancing service is less costly than building new storage capacity.

NCGC recommends that the Commission go beyond PG&E's proposal and expand the amount of capacity assigned to balancing by adding an additional 25 MMcf/d of injection capacity, resulting in 100 MMcf/d of injection capacity. The additional injection capacity could reduce the number of high OFOs by 34%. If injection capacity were increased to 100 MMcf/d, high OFOs could be reduced from 79 to 52 utilizing the April 2000 to October 2002 data that PG&E used.

PG&E's proposed addition of 25 Mdth/d of injection capacity to the balancing function adds $1.56 million to the cost of balancing service. Increasing the amount of injection capacity by another 25 MMcf/d to a total of 100 MMcf/d would add another $1.56 million.

The only parties who object to PG&E's proposal for increasing balancing capacity are the Indicated Producers, and the two third party storage providers. The Indicated Producers argue that the data upon which PG&E relies are not persuasive and are stale. NCGC points out that although the March 2000 study was entered into the record, PG&E conducted a new study to predict the number of OFOs that would have been experienced during April 2000 through October 2002 if increased storage injection and withdrawal capacity had been available for balancing service. This was presented in Figure 8-1 of Ex. 1 at 8-11.

LGS and Wild Goose contend that instead of using PG&E's own storage capacity, that PG&E should acquire additional storage capacity for the balancing function from them. NCGC points out that neither LGS nor Wild Goose have committed that they would make storage capacity available for the balancing function at a cost that would meet or beat the revenue requirement associated with the depreciated installed capacity that PG&E would add to the balancing function. Also, as PG&E witness Johnson pointed out, PG&E needs to have direct control over the storage capacity so that pipeline operators have the ability to make numerous adjustments throughout the day to ensure safe and reliable operations. Also, if LGS or Wild Goose provide the storage capacity, the opportunity to add storage capacity to the balancing function at depreciated embedded cost may be lost to PG&E customers for a long time. If this assignment of existing storage capacity to the balancing function is not seized, the storage capacity could be sold for an undetermined number of years.

NGC also contends that all customers, core and noncore, benefit from expanding PG&E's capacity to provide balancing service and to avoid OFOs. Also, the cost of the expanded load balancing service would be shared among all customers, insofar as load balancing storage costs are bundled in backbone transmission rates. In light of PG&E's study of the benefits of expanding the amount of capacity allocated to the load balancing function, and in light of the broad sharing of both the benefits and the costs of the expansion, NCGC recommends that the Commission approve an expansion as proposed by NCGC.

(1) Daily Imbalance Limit

PG&E proposes to impose a new daily imbalance limit that would be plus or minus 35% of daily usage or plus or minus 30,000 dth, whichever is larger. PG&E proposes to charge a $0.25/dth excess imbalance charge on all daily imbalances that exceed the proposed daily imbalance limit.

NCGC opposes PG&E's proposal to impose a daily imbalance limit under ordinary pipeline operating conditions when OFOs have not been declared. PG&E has not shown that this is necessary. PG&E witness Johnson testified that a study of daily imbalances incurred by all balancing entity groups during 2000 and 2001 revealed that only two percent of daily imbalances exceeded the proposed daily limit. NCGC contends that the daily imbalances under non-OFO conditions does not warrant imposing a penalty scheme on all customers at all times, even when the system as a whole is in balance.

As an alternative to imposing daily balancing limits, NCGC witness Pretto proposes that PG&E explore improvements to the OFO process that would bring more focused attention on those who are the cause of large daily customer imbalances. NCGC contends that this approach would relieve the vast majority of transportation customers from potentially suffering the prospect of daily imbalance charges that are intended to address an infrequent, intermittent problem that is not of their making.

(2) Imbalance Charge

Currently, customers are required to balance their monthly supply and demand within a 5% tolerance band. After the end of a month, customers are allowed to trade monthly imbalances with other customers or into a storage account. Customers are permitted to carry imbalances between zero and 5% into the next month. At the end of the trading period, PG&E uses a cash-out mechanism to purchase positive customer imbalances outside of the 5% monthly tolerance band. PG&E uses the same mechanism to sell gas to customers that have negative imbalances outside the 5% tolerance band.

PG&E proposes to replace the current cash-out process with an imbalance charge for monthly imbalances in excess of the 5% tolerance band. A customer's entire monthly gas supply imbalance, including any quantity beyond the five percent monthly tolerance limit, would be carried forward to the subsequent month.

NCGC supports the continuation of the existing cash-out process. NCGC contends that PG&E has failed to show a need to eliminate the cash-out process. Although PG&E contends that the economic impact of cashing out monthly imbalances beyond the 5% tolerance flows to customers, the contrary is true. NCGC points out that when PG&E buys or sells gas to "cash out" imbalances beyond the 5% tolerance, the costs are allocated to the BCA, which is allocated to all customers. The revenues are also allocated to the BCA, and revenues outstrip costs. For the period March 1998 through December 2001, PG&E received revenues of $14.7 million for cash-out sales and incurred expenses of $2.2 million for cash-out purchases.

NCGC asserts that it should be expected that PG&E makes money on cash-outs. Under Schedule G-BAL, the cash-out price paid to customers for positive imbalance gas is 75% of the Weighted Over Delivery (WOD) index, an index of the lowest prices experienced during the month in which the imbalance occurred. The cash-out price charged for gas sold to customers to cash-out negative imbalances over 5% is 125% of the Weighted Under Delivery (WUD) index, an index that reflects the highest prices experienced during the month in which the imbalance occurred. Thus, a customer that remains out of balance so that a cash-out occurs has his imbalance bought or sold by PG&E at a price that is disadvantageous for the customer and advantageous for PG&E.

NCGC contends that the cash-out prices in Schedule G-BAL provide a marked incentive for a customer to stay within the 5% monthly imbalance tolerance and not allow a cash-out to occur. The current cash-out mechanism sufficiently penalizes an out-of-balance customer without imposing the further penalty of leaving imbalance gas in the hands of the customer for disposition the following month.

(3) Curtailment Process

PG&E proposes to replace the involuntary diversion process that was developed in the Gas Accord with a curtailment process. When noncore demand must be reduced to ensure continuous service to core customers, the curtailment would be pro rata across all noncore customers. PG&E states that the existing diversion process is slow and cumbersome, and because the process applies to backbone transportation shippers, it is difficult to prioritize the diversion supplies down to specific noncore customers.

PG&E's proposed curtailment process would be applied on either a system wide basis or on a particular local transmission system, as necessary. The curtailments to noncore customers would be pro rata, as opposed to a rotating curtailment block system, so that all noncore customers have some allowed gas usage.

NCGC does not believe that PG&E has adequately explained the details on how the pro rata curtailment process would work. In order to resolve these implementation issues, NCGC believes that a workshop should be held to address the details of PG&E's curtailment process. PG&E agrees that a workshop is appropriate. NCGC recommends that PG&E's proposal to adopt a pro rata curtailment scheme be approved, but that a workshop be convened to resolve the various details of how curtailments would work.

10. ORA

ORA is opposed to PG&E's proposed $60 per Dth penalty for core customers, and that customers pay the market price and purchase supply from noncore customers with excess capacity. PG&E's rationale is that this proposed penalty would provide an incentive for core customers to properly forecast their demand based on PG&E's proposed 1-in-10 year winter reliability standard, and that it will provide an incentive for noncore customers to sell, at true market prices, their excess capacity to core customers.

ORA does not believe that the proposed penalty is justified, and questions PG&E's rationale. ORA contends that PG&E has not made any showing that the core class has habitually underestimated its capacity needs. PG&E's own witness testified that he believes that CPGs would endeavor to meet their demand at any level, even if it is above the proposed 1-in-10 year winter reliability standard. ORA does not believe that the imposition of penalties on core customers for underestimating their needs will persuade noncore customers to sell, at true market prices, their excess capacity to the core class. Instead, noncore customers might withhold their excess capacity in order to drive up market prices, and core might have to pay higher than market prices in order to avoid paying PG&E's $60 per decatherm penalty.

ORA contends that because there is a correlation between PG&E's winter reliability standard and the proposed increased core penalties, if the Commission rejects PG&E's proposed winter reliability standard, PG&E's proposed OFO or EFO penalties should be rejected as well.

11. Palo Alto

Due to the procedural schedule and constraints on the parties' resources, Palo Alto does not believe that PG&E's proposals have been adequately reviewed. These proposals include replacing the diversion process with a curtailment process, increasing the amount of storage capacity balancing, establishing the daily imbalance limit, and requiring CPGs to balance based on the 7:15 a.m. forecast on the day of flow.

Palo Alto also contends that PG&E has failed to establish that these proposed changes are needed at the present time.

12. SPURR/ABAG

The School Project for Utility Rate Reduction and the Assoication of Bay Area Governments Publicly Owned Energy Resources (SPURR/ABAG) agree with ORA that PG&E has provided no justification for a penalty equal to $60 per Dth, plus the daily citygate price of gas, for core customers that are out of balance in an EFO event. Currently, on an EFO day, a penalty of $50 per dth is imposed upon both core customers and noncore customers that are out of balance. Although PG&E proposes to increase the EFO penalty dramatically for all customers, PG&E proposes an even higher EFO penalty for core customers than for noncore customers. This differential treatment of core customers and noncore customers is not supported by the evidence. SPURR/ABAG contend that the penalties for customer noncompliance with an EFO should be proportionate to the harm caused to other customers. It is sufficient to impose either a fixed dollar penalty or a small dollar penalty, in addition to the actual cost of gas on the EFO day. It is not appropriate to combine a substantial fixed dollar penalty with the actual cost of gas, and it is not appropriate to establish different fixed dollar penalties for core and noncore customers.

13. Wild Goose

PG&E proposes to eliminate the involuntary diversion process and replace it with a curtailment procedure. Wild Goose is not opposed to PG&E's proposal, but PG&E should ensure that the curtailment procedure does not negatively impact the use of storage.

PG&E notes that one of the benefits of curtailment over diversion is that it allows the scheduling process to continue, which assures that additional supply from transmission and storage can be scheduled throughout the curtailment period. Wild Goose asserts that this provides value to storage holders, and serves as an incentive to contract for, and utilize, storage. This incentive, however, may be offset by PG&E's proposed methodology of requiring the load reduction to be shared across all noncore end use customers on a pro rata basis. Thus, even a noncore customer who contracted for storage would be curtailed in the same fashion as a customer who did not take such precautions. That is, the customer that contracted for storage will not be able to use firm storage withdrawals to avoid the curtailment.

Wild Goose asserts that unless PG&E's curtailment plan allows noncore customers to withdraw gas from storage, PG&E's proposal will only serve deter customers from utilizing storage. PG&E and the Commission should, instead, be encouraging customers to store gas for periods of high demand.

PG&E's proposes a daily imbalance limit, with a wide tolerance band. This daily imbalance limit is proposed at plus or minus 35% of daily usage, or plus or minus 30,000 Dth, whichever is larger. If a customer exceeds this daily imbalance limit, a charge of $0.25 per Dth will be assessed. Wild Goose supports the adoption of this proposal with a slight modification. Wild Goose suggests that the daily imbalance limit be the lesser of plus or minus 35% of daily usage, or plus or minus 30,000 Dth. By making this change, the proposed limitation would apply to more customers. If this stricter standard were used, PG&E testified that approximately 33% of the imbalances created during 2000 and 2001 would have been subject to the proposed imbalance penalty. Wild Goose contends that such a modification would more accurately assign the costs of daily imbalances to those responsible for the imbalances and, more likely than not, have a greater impact on the reduction of OFOs.

Wild Goose also contends that if PG&E's daily imbalance proposal is to reduce the number of OFOs, the proposed penalty of $0.25 per Dth is insufficient in light of the fluctuations in gas prices. Instead, the penalty should be set at a level that will truly act as a deterrent.

Wild Goose points out that a number of parties object to PG&E's proposal to establish a daily imbalance limit. Since PG&E's current tariff requires customers to match supply and demand on a daily basis, each day a customer fails to do so is out of compliance with the tariff. Thus, PG&E's proposal is merely to assess a small penalty on those who are grossly out of compliance with its already approved tariff requirements. Since the proposed imbalance tolerance band will only capture the very large imbalances that drive the system to its pipeline inventory threshold resulting in an OFO, PG&E is only targeting the individuals that are creating the imbalances.

In order to more accurately assign the costs of daily imbalances to those responsible for the imbalances, the proposed imbalance tolerance band should be made more restrictive as Wild Goose recommends. At a minimum, the Commission should adopt PG&E's proposal leaving open the possibility of revisiting this issue as part of the OFO forum process.

14. PG&E

For PG&E's gas operations and balancing services, PG&E proposes to maintain the general structure, while making several changes to enhance or improve existing operational provisions. PG&E contends that these proposals will enhance operations and balancing services, especially during crisis periods. The proposed improvements are: (1) replacing the current diversion process with an end-use load curtailment process; (2) assigning additional storage capacity to the balancing service; (3) applying balancing rules and penalties to California gas production balancing entities so that these provisions are consistently applied to all market participants; and (4) allowing firm capacity to bump as available capacity in the second and third cycles consistent with interstate pipeline nomination standards. In certain instances, PG&E is willing to work out the implementation details in a workshop.

PG&E proposes to increase the storage capacity allocated to the balancing service to 75 MMcf per day of injection and withdrawal and 4.0 Bcf of inventory, from the existing levels of 50 MMcf per day of injection, 70 MMcf per day of withdrawal and 2.2 Bcf of inventory. PG&E contends that the added storage capacity will reduce the incidence of OFOs. By reassigning existing firm storage to balancing, and expanding storage for this purpose, PG&E is able to minimize costs.

The other adjustments that PG&E proposes are not a substitute for the added storage capacity, but instead are intended to reduce the number of OFOs by limiting some very large and adverse imbalances created by a few market players.

As for LGS' suggestion that PG&E should look to third-party storage providers for the incremental storage capacity, PG&E contends that this would jeopardize the effectiveness of the storage assets allocated to balancing, and also the balancing service since LGS is balanced on PG&E's system.

PG&E proposes to add a wide daily imbalance tolerance limit to the monthly balancing service option to discourage the extremely large daily imbalances that are created by a few balancing entities on the system. The proposed daily imbalance limit is the larger of either plus or minus 35 percent of daily usage, or plus or minus 30,000 Dth. An excess daily imbalance charge of $0.25 per Dth would be used as an incentive to stay within the limit.

Although Duke and NCGC suggest customer-specific OFOs or targeting customers that create the imbalance leading to OFOs, it has been PG&E's experience that such specific measures do not work because targeted customers who are out of balance simply trade their imbalances with non-targeted customers. Although this results in the targeted customer being in balance, the net impact is that the system remains out of balance.

PG&E contends that its daily imbalance proposal accomplishes what NCGC suggests by bringing more focused attention on those who are the cause of large daily customer imbalances. The proposed daily tolerance band is so wide that it targets customers creating very large daily imbalances. Only 2% of the daily customer imbalances actually created during 2000 and 2001 would have exceeded the proposed tolerances. PG&E's proposal also focuses customer attention on daily imbalances by adding a mechanism that provides some financial consequence when the daily balancing obligation, which exists under today's tariff without financial consequence, is ignored. PG&E contends that the proposed limit is wide enough that PG&E believes it would be extremely rare that a customer who is actively attempting to manage the balancing obligations would never exceed this limit.

Wild Goose proposes that the tolerance limit be more stringent, i.e., the lesser of plus or minus 35 percent, or plus or minus 30,000 Dth. PG&E believes that although this would provide more incentive for customers to remain in balance, it may be too restrictive because over 33% of the daily imbalances would be affected. PG&E believes that its proposed financial incentive will be adequate to eliminate the large imbalances that result in the calling of an OFO.

The Indicated Producers recommend that the daily imbalance requirement be rejected or deferred until the impact of other proposals can be evaluated. PG&E contends that its daily imbalance proposal is an appropriate response to encourage those customers not meeting the obligations under the existing tariff to reduce imbalances so they do not impact other customers.

PG&E proposes to replace the existing cash-out mechanism with an imbalance charge mechanism. This would apply to imbalances that exceed the monthly imbalance limit after the imbalance-trading period has concluded. PG&E asserts that the new proposal would eliminate the gaming associated with the existing cash-out mechanism. The proposed imbalance charge would hold the customer responsible for offsetting the physical imbalance. The proposed charge creates an incentive for the customer to be within the monthly imbalance limit after the trading period.

NCGC's reason for retaining the current cash-out mechanism is that it is responsive to the commodity cost of gas. PG&E contends that this is the reason why it should be replaced with the noncompliance charge. PG&E says that the problem is that customers compare the cash-out prices to the cost of gas in the next month. With significant price swings in daily and monthly gas prices, the cash-out prices can become an attractive economic alternative for the customer. The purpose of the current cash out mechanism and the proposed monthly imbalance charge is to impose a penalty to create the incentive for customers to keep their imbalances within the monthly tolerance level. These mechanisms are not effective if the customer uses them for economic gains.

PG&E proposes that California gas production imbalances, which are managed by a balancing entity through a CPBA, be subject to the same OFO requirements and noncompliance charges applicable to all other balancing entities. A CPBA imbalance is equal to the difference between the scheduled nominations of gas supply and the actual metered gas production flow. PG&E asserts that the OFO balancing requirements and noncompliance charges will remedy the problem of nominating gas in response to an OFO, even though there is not a physical increase or decrease in production. This paper imbalance can then be sold or traded to an end-user balancing entity to offset their real imbalance position, and avoid having to pay the OFO imbalance charge. The problem is that there is no change in the physical imbalance on the system.

PG&E proposes to replace the involuntary diversion process with a noncore customer curtailment process. PG&E contends that this will improve the ability to quickly reduce demand when a supply/demand imbalance threatens service to core customers. Duke, NCGC, and Wild Goose support PG&E's proposal but suggest certain refinements to the final development of the allowed burn quantities which establish the benchmark from which curtailment compliance is measured, and that storage gas withdrawal be utilized like a stand-by fuel to avoid or minimize curtailment. PG&E remains open to exploring and developing these refinements in a workshop or working group setting.

PG&E asserts that the concerns raised by the CCC/Calpine and the Indicated Producers are not sufficient to justify retaining the current diversion process. The concern that PG&E's proposal undermines the Gas Accord structure for backbone transmission rights is wrong because the proposal has no impact on the firm and as-available contract structure under the Gas Accord. Instead, PG&E's proposal offers a fair pro-rata burden on all noncore end-use customers during curtailments. When as-available contracts are diverted under the existing diversion process, the marketers holding the contracts decide which of their noncore customers are curtailed, which could result in some noncore customers having to bear a disproportionate share of the diversion burden.

Another concern of CCC/Calpine is that PG&E's proposal may provide PG&E's Core Procurement Department with an incentive to rely on curtailments rather than to acquire sufficient gas supply. PG&E contends that there is a significant incentive for its Core Procurement Department to have gas under contract because if there is insufficient gas, it will face a noncompliance charge of the market price plus a $60 per Dth imbalance charge, which is greater than the $50 per Dth for diverted gas. PG&E also contends that PG&E's Winter Reliability Standard proposal will also require PG&E's Core Procurement Department to meet a 1-in-10 year cold year event with firm capacity and supply, which reduces the need for noncore diversion or curtailment.

PG&E also points out that the curtailment process is easier to institute than a diversion process because PG&E is directly in contact with the end-user, whereas in a diversion a gas marketer may have to contact the end-use customer, who then is likely to check with PG&E before the end-user curtails its gas use.

CCC/Calpine also expressed concern above the value of keeping all four nomination cycles for the gas day during a curtailment event. PG&E contends that even if there is a limited amount of supply, there is a large incentive for added supply to be made available in the later nomination cycle. Under the diversion process, all nominations are halted after the first cycle, so even if gas is available, no more gas can come onto the system. Keeping the nomination cycle in place allows the possibility of more gas flowing onto the system that is short on supply.

CCC/Calpine propose that CPGs compensate noncore customers for curtailed quantities at a rate equal to the daily gas index price plus $10 per Dth. The Indicated Producers support this as well. PG&E recommends that this proposal be rejected because the gas supply is not taken from curtailed customers or their marketer and given to core customers. Instead, the gas supply remains with the original noncore customer unless or until it is renominated to another customer. If CPGs do not have enough supply to meet their demand, the CPGs will need to buy the supply from the curtailed suppliers or face high penalties of $60 per Dth, plus the daily citygate-indexed price of gas. Thus, curtailed customers will be in a position to readily sell the gas to CPGs at a market price.

PG&E asserts that the CCC/Calpine proposal will penalize CPGs by forcing them to purchase a positive imbalance from a noncore customer when there is an emergency. This will only provide a windfall to the curtailed noncore customers, and may provide an incentive for a curtailed noncore customer to withhold selling their extra gas supply to a CPG during a curtailment crisis.

ORA opposes the $60 per decatherm penalty for core customers who improperly forecast their demand. PG&E says that ORA misunderstands PG&E's proposal. The $60 per decatherm plus the daily cost of gas noncompliance charge proposal would be applicable during an EFO. PG&E states that the EFO noncompliance charge is not for improperly forecasting demand level. Instead, it is applicable when the supply that the CPG delivers to the PG&E system is less than the forecasted demand level provided to the CPG by the pipeline operator.

PG&E states that the Indicated Producers appear to argue that the existing diversion provisions provide a benefit to noncore end-users in that the noncore customer is paid $50 per Dth for its diverted gas supply and that the market price for selling the gas to a CPG may be less than $50 per Dth. PG&E points out that the diversion charge of $50 per Dth would go to the backbone shipper, most likely a marketer, and not the curtailed end-use customer. Under PG&E's system curtailment proposal, the curtailed noncore customer can sell their extra gas to a supply-short CPG at a market price. This market price could be very high. PG&E also contends that because noncore customers pay lower local transmission rates which reflects a lower level of reliability, CPGs should not be forced to pay curtailed noncore customers a fixed price for curtailed gas supply that might be higher than the market price. PG&E contends that its market price mechanism under its curtailment proposal is the fairest approach for both curtailed noncore customers and supply-short core customers.

The Indicated Producers recommend that the curtailment protocol proposal should be modified to incorporate a firm versus interruptible distinction. PG&E points out that end-use customer delivery rights exist under local transmission tariffs and contracts, which have no firm or as-available distinction for noncore end-use customers under either the existing diversion process or the proposed curtailment process. The delivery point rights are the same for all noncore customers and are lower in priority than for core customers.

The Indicated Producers also make a proposal to retain the existing tariff language requirement that the core take all reasonable steps, including using (or attempting to use) its capacity and any as-available capacity before defaulting to a curtailment. As indicated by PG&E's witness, PG&E will continue to include this language in its tariffs.

CMTA opposes PG&E's proposal to replace the existing diversion process with a curtailment process. CMTA asserts that PG&E's proposal runs contrary to the structure of the Gas Accord, the proposal would absolve PG&E from wise management of transportation and storage capacity and gas procurement, and the proposal would provide an incentive to curtail. PG&E contends that the curtailment proposal does not undermine the primary contract rights established under the Gas Accord.

PG&E contends that CMTA's claim that the curtailment proposal will have noncore bearing the consequences of the failure of the core to get enough supply is not true. PG&E says that the diversion mechanism is not likely to be effective during a true emergency, so PG&E has proposed a system level curtailment procedure. Although this places a burden on noncore customers, the debate is over how this burden is imposed. As PG&E witness Johnson testified, the core has a significant incentive to buy gas at the market price from noncore customers (or their agents) under these emergency conditions.

Contrary to CMTA's argument, PG&E asserts that the core has an increased incentive under PG&E's curtailment proposal to have sufficient gas supply arrangements in place for cold temperature conditions compared to today's diversion procedure. Under today's diversion mechanism, core pays a $50 per Dth EFO imbalance penalty charge, and pays $50 per Dth diversion charge to the marketer for the gas supply. The second diversion charge effectively purchases gas supply from the noncore customer's gas marketer.

Under the proposed system curtailment mechanism, core pays a penalty of $60 per Dth plus the market price. In addition, core must still buy the gas at the market price in order to meet its balancing obligations. The total potential cost to core may be substantially increased, especially since the market price is likely to be very high during these emergencies. For example, if the market price is $40 per Dth, the total cost to core remains $100 per Dth ($50 per Dth EFO noncompliance plus $50 per Dth diversion charge) under a diversion, but increases to $140 per Dth ($60 per Dth plus the $40 per Dth market price for EFO noncompliance plus the $40 per Dth market price for the gas supply that the core still needs to purchase under the proposed system curtailment. Under the diversion process, the backbone shipper, and not the noncore customer, would receive the $50 per Dth diversion charge. Under the system curtailment procedure, the noncore customer, not the marketer, would be able to sell its gas supply to the core through a prearranged supply contract or on the gas day. The likely outcome is that the noncore customer will receive more compensation under PG&E's proposal than under today's mechanism. PG&E asserts that when a curtailment event occurs, there is an emergency situation on the pipeline, and it is not appropriate for marketers of noncore customers to benefit from emergency conditions.

C. Discussion

1. Balancing Service Proposals

a. Additional Storage Capacity

PG&E proposes to increase the storage capacity for its balancing service by increasing injection from 51 MDth/d to 76 MDth/d, increasing inventory from 2.2 MMDth to 4.1 MMDth, and increasing withdrawal from 71.4MDth/d to 76 MDth/d. In addition, PG&E proposes to allocate gas commodity to the balancing service. This would come from a transfer of 2 MMDth of non-cycle working gas which PG&E would reclassify as working gas for its balancing service.

PG&E presented testimony on the effect that increased injection, inventory, and withdrawal would have on OFOs. This was presented in Figure 8.1 of Exhibit 1. The storage study, Exhibit 18, which PG&E cites as support for the additional balancing, was used in cross-examination of the PG&E witness. Based on the storage study, and assuming customer balancing behavior remains constant, PG&E predicts that an additional 25 MDth/d will reduce the number of high OFOs by 20%, or by about 15 OFOs. (Ex. 1, p. 8-11; Ex. 18; 4 RT 424-425; 6 RT 550.) Although LGS asked questions of the PG&E witness regarding the data and assumptions supporting Figure 8.1, none of the other parties presented any testimony which contradicts the relationship shown in Figure 8.1 of Exhibit 1. (See 6 RT 565-579.)

NCGC suggests that an additional 25 MDth/d of injection capacity be added to PG&E's proposal. According to PG&E's analysis, this would reduce the number of OFOs even more. We do not believe that this extra 25 MDth/d of additional injection is needed at this time. Instead, PG&E's proposal should be implemented and monitored over 2004 to determine how effective this additional storage capacity will be.

LGS also raised the issue of whether additional balancing should be provided by third party storage providers. Exhibit 18 described some contacts that PG&E had with Wild Goose, and with Western Hub Properties, a parent company of LGS. Exhibit 18 contained some preliminary estimates of how much these two storage providers could provide the service for in the 2000 to 2001 timeframe. Although this raises a cost savings issue, PG&E is the entity that has the responsibility and certificated authority to provide gas services to its customers.

Based on the record in this proceeding, we adopt PG&E's proposal to increase its storage capacity for its balancing service by increasing injection to 76 MDth/d, increasing the inventory to 4.1 MMDth, and increasing withdrawal to 76 MDth/d. Those increases are reflected in the assignment of storage capacity for 2004 shown in Table 4.

PG&E shall monitor the effectiveness of this additional storage capacity in its daily operations and balancing. PG&E shall provide a report in its 2005 transmission and storage rate case about this additional storage capacity, and its effects on the system.

Next, we turn to PG&E's proposal to allocate 2 MMDth of gas to the balancing service for 2004. PG&E proposes that the gas come from a transfer of 2 MMDth of non-cycle working gas, which PG&E seeks to reclassify as working gas for its balancing service.

No one has objected to PG&E's proposal to reclassify this non-cycle working gas as working gas for use in its balancing service. Based on the benefit that the increase in balancing will bring using existing assets, we adopt PG&E's proposal to reclassify the 2 MMDth of gas as working gas for use in PG&E's balancing service.

b. Daily Imbalance Limit For the Monthly Balancing Option

PG&E proposes to impose a daily imbalance limit, with a wide tolerance band. PG&E also proposes that a $0.25 per Dth excess imbalance charge be imposed for all daily imbalances that exceed the daily imbalance limit.

Several parties believe that the daily imbalance proposal and related charge do more harm than good. Instead of punishing the entities who cause large imbalances on the system, PG&E's proposal would penalize those who are out of balance on a particular day, but do not contribute to the system imbalance.

Since the daily imbalance proposal is to reduce imbalances and the number of OFOs, some of the parties suggest that other measures targeting the offenders should be used by PG&E. Some also suggest that the additional storage capacity for balancing should be used first to determine if it helps solve the OFO problem before imposing the daily imbalance penalty.

PG&E's proposal seems to affect a large group of customers who are not the cause of large system imbalances. To impose an excess imbalance charge on them on a daily basis at this time is counterproductive. PG&E should explore other ways in which to target those who cause the imbalances, which lead to OFOs. We also agree with some of the parties that the additional storage capacity for balancing services should be used first to determine its effect on managing imbalances and OFOs, before additional measures are considered to remedy these problems.

Accordingly, PG&E's proposal for a daily imbalance limit and related excess imbalance charge is not adopted.

c. Disposition of Monthly Imbalances

PG&E proposes that instead of using the current cash-out mechanism, that it be replaced with an imbalance charge for monthly imbalances in excess of the five percent tolerance band. This imbalance charge would be 100% of the MCI. The imbalance would be carried forward, and the customer would be responsible for clearing the imbalance. PG&E also proposes that for contracts that are terminated, the prices at which PG&E buys and sells gas from these entities be changed to the MCI for a negative imbalance cash-out, and the LCI for a positive imbalance cash-out.

NCGC opposes the elimination of the cash-out mechanism, and points out that the mechanism generates revenues. NCGC also points out that the cash-out prices in Schedule G-BAL provide an incentive for a customer to stay within the 5% monthly imbalance tolerance, and that PG&E's cash-out is disadvantageous for the customer and advantageous for PG&E.

PG&E's rebuttal testimony in Exhibit 4 explained that the volatility in gas prices lead some customers to accumulate large monthly imbalances that they will cash out when prices appear attractive. PG&E's testimony also states:

"This excessive imbalance is then effectively sold to (or purchased from) the pipeline and is a permanent transfer into (or out of) the storage inventory allocated for the balancing service. When these cash-outs are large, or when they cumulatively move in the same direction, the available storage inventory to support balancing services can be filled (or depleted). As a result, the balancing service available to the market is limited, impacting all customers." (Ex. 4, p. 8-9.)

On balance, we believe the current cash-out mechanism is advantageous for ratepayers, as the revenues and expenses go into the BCA. The prices used for the cash-out are also advantageous. The only apparent impact is to the balancing operations. However, with the additional storage capacity assigned to balancing, this should help the problem that PG&E has described.

Accordingly, we do not adopt PG&E's proposal to replace the cash-out mechanism with an imbalance charge for monthly imbalances in excess of the tolerance band. For 2004, PG&E shall continue to use the existing cash-out mechanism.

With respect to the prices at which PG&E buys or sells gas for terminated contracts, no one has commented on the proposed rates that PG&E proposes to use. We adopt PG&E's proposal that for contracts that are terminated, the prices at which PG&E buys and sells gas from these entities be changed to the MCI for a negative imbalance cash-out, and the LCI for a positive imbalance cash-out. .

d. OFO Obligations for California Gas Production

As part of the Gas Accord Settlement Agreement, PG&E and the California gas producers agreed that a standard CPBA would be implemented. (73 CPUC2d at 835.) Under the CPBA, the balancing rules for California production gas differ from the balancing rules for end-use customers, and do not have OFO or EFO noncompliance charges.

According to PG&E, the majority of California production gas is under the management of end-use customers, who are subject to flow order noncompliance charges. PG&E contends that the nominations of California production gas are being used in a way that offset end-use customer imbalances to avoid OFO or EFO noncompliance charges.

PG&E proposes that California gas production imbalances be subject to the same OFO and EFO tolerance bands and noncompliance charges as other end-use customers.

In support of PG&E's proposal, PG&E developed Table 8-1 of Exhibit 1 which shows 45 OFOs over a period of two years, and Table 8-1 of Exhibit 4 which shows CPBA nominations, actual production, and imbalances for June 2002. The data presented shows that in 35 of the 45 OFO events, California gas production imbalances exceeded the tolerance band required by the OFO.

CNGPA did not present any testimony which refutes the data shown in the two tables, nor did CNGPA's testimony or its reply brief address the table or PG&E's conclusions about the tables. Instead, the arguments of CNGPA focused on why the application of the same rules and charges as other end-use customers would be discriminatory, in violation of certain provisions of the Public Utilities Code, and why it would be difficult to comply with the OFOs.

We are not persuaded that the proposal of PG&E to apply the same OFO and EFO rules and charges that other end-user have would discriminate against California gas producers. PG&E is merely applying the same set of rules in 2004 to California gas producers and other end-use customers. As part of the Gas Accord, PG&E and the California gas producers agreed to the implementation of the CPBA. However, the extension of the Gas Accord ends on December 31, 2003. Instead of treating California gas producers differently in 2004, they will be treated the same as other end-use customers.

CNGPA also cites §§ 785 and 785.2 as reasons why PG&E's proposal should not apply to California gas production. Our reading of those code sections do not suggest that PG&E's proposal would violate those provisions of the Code.

With regard to CNGPA's arguments that they are being denied access to real-time operating and balancing data, and to PG&E's flow patterns and pipeline pressures, PG&E shall be directed to work with CNGPA to resolve these issues so that CNGPA can timely respond to any OFO or EFO that might be called.

Based on the record, PG&E's proposal to apply the same OFO and EFO tolerance bands and noncompliance charges that are currently in place for end-use customers, to California gas production, is adopted.

e. Measuring Core Procurement Groups' Compliance

PG&E recommends that three proposals be adopted for CPGs. The first proposal is to use the Determined Usage forecast to calculate the compliance of CPGs with flow orders. The second proposal is that the EFO noncompliance charge for all CPGs be calculated using the lower of the Determined Usage or the end-of-flow-day core demand forecast, as compared to the CPG's scheduled supply. PG&E's third proposal is that the EFO noncompliance charges for CPGs be set at a higher level than for noncore customers.

ORA and SPURR/ABAG raised concerns regarding the noncompliance charge for CPGs in the event of an EFO. They point out that the core's noncompliance charge ($60 plus DCI per Dth) should not be higher than the noncore's compliance charge ($50 plus DCI per Dth), and that the index component of the charge should not be used.

We agree with ORA and SPURR/ABAG that PG&E has not demonstrated why the core's noncompliance charge for an EFO should be higher than the noncore's charge. We address the index argument later in this section, and determine the gas index component should be used. The EFO noncompliance charge for CPGs shall be equivalent to the noncore's EFO noncompliance charge of $50 plus DCI per Dth. Thus, PG&E's proposal that the EFO noncompliance charge for CPGs be set at a higher level than for noncore customers is not adopted. Instead, PG&E shall use the same EFO noncompliance charge for both CPGs and noncore.

No other party submitted any testimony or raised objections to the two other PG&E proposals.

We adopt PG&E's proposal to use the Determined Usage forecast to calculate the compliance of CPGs with flow orders. We also adopt PG&E's proposal that the EFO noncompliance charge for all CPGs be calculated using the lower of the Determined Usage or the end-of-flow-day core demand forecast, as compared to the CPG's scheduled supply.

2. Bumping Proposal

PG&E proposes to adopt the NAESB bumping process into its gas nomination process.

No one submitted any testimony or raised any objections to PG&E's proposal. We adopt PG&E's proposal to include the NAESB bumping process as part of PG&E's gas nomination process.

3. Supply Shortfalls and Capacity
Constraints Proposals

a. Diversion or Curtailment

PG&E's proposed curtailment process seeks to remedy some operational concerns with the current diversion process. However, as noted by PG&E, the involuntary diversion process has never been used.

Several of the parties have expressed concerns about how the curtailment process would work under certain situations. PG&E's proposal leaves a lot of these questions unanswered. Although the parties appear willing to work out the details in a workshop, it is unclear whether a workshop would resolve all of these concerns.

Other parties also expressed concern about the impact a curtailment could have on a business, and that curtailed noncore customers would not be compensated, as they would be under a diversion. The third party storage providers believe that a curtailment process must also allow for a storage customer to withdraw gas that is already in storage.

We have considered the testimony of the parties on this subject, and the arguments of the parties. We believe that the curtailment process should be developed further by PG&E and other interested parties before we consider whether it should be adopted. Instead of adopting a curtailment process with a lot of unknowns, or tentatively approving a process subject to a workshop, we believe that the existing curtailment process and rules from the Gas Accord should remain in place for 2004.

Should PG&E continue to believe that a curtailment process is a more appropriate tool, PG&E should develop its proposal further. Since many of the parties expressed a willingness to hold a workshop, it is in PG&E's interest to discuss its curtailment plan with these parties in 2004. We will permit the curtailment issue to be addressed in the 2005 rate case.

Accordingly, we do not adopt PG&E's proposal to replace the existing diversion process with a curtailment process for 2004, nor do we adopt the related noncompliance charge for a system-level curtailment. Instead, the current diversion process and rules shall remain in effect for 2004.

b. Local Curtailments

PG&E proposes to continue the existing local curtailment process as described at pages 8-30 to 8-31 of Exhibit 1. Currently, there is no noncompliance charge for a local curtailment. PG&E proposes that a $50 plus DCI per Dth noncompliance charge be imposed for usage that exceeds the maximum allowable usage quantity. The payment of the noncompliance charge does not relieve the customer of the duty to resolve any imbalances, and the customer is also subject to any EFO or OFO noncompliance charge.

None of the other parties presented any testimony on the local curtailment process or the proposed noncompliance charge.

We adopt the current local curtailment process for use in PG&E's gas structure for 2004 and 2005. We also adopt PG&E's proposal for a $50 plus DCI noncompliance charge for local curtailments for use in 2004.

4. Shrinkage Proposals

PG&E has two shrinkage proposals. The first proposal is to update the shrinkage allowance on an annual basis, and if needed, to file separate advice letters during the year to adjust the shrinkage allowances to better match the actual shrinkage experienced on the system. The second proposal is to collect the cost of GDU and LUAF associated with PG&E's gas storage operations, from all scheduled storage injection volumes through an in-kind shrinkage allowance.

No other parties submitted any testimony or filed comments on PG&E's shrinkage proposals.

PG&E's proposal to allow PG&E to update its shrinkage allowances on an annual basis through an advice letter compliance filing, and, if necessary, to make separate advice letter filings to adjust shrinkage allowances at other times of the year in order to better match the actual shrinkage experienced on PG&E's system, is adopted. The annual filing for 2004 shall occur on or before December 31, 2003, with an effective date of January 1, 2004. The BCAP shall continue to be the proceeding in which the pipeline shrinkage calculation methodology is determined, and the proportion of LUAF and GDU that are to be assigned to transmission and distribution shrinkage.

PG&E's proposal that an in-kind shrinkage allowance, using the methodology described at page 8-34 of Exhibit 1, be applied to all scheduled storage injection volumes, is adopted. The gas storage shrinkage costs that are currently collected through the transportation in-kind shrinkage allowances are to be excluded from the transmission and distribution in-kind shrinkage allowances. PG&E's proposal that it be allowed to continue to recover in storage rates a portion of the cost of electricity used by PG&E's gas department to operate its storage field is adopted.

Due to the non-adoption of PG&E's request to sell the non-cycle working gas, the storage cycle quantity has been changed. PG&E shall calculate the in-kind shrinkage allowance for the 2004 injection season, and shall make an advice letter compliance filing no later than March 19, 2004.

5. Noncompliance Charges Proposal

PG&E proposes that most of the noncompliance charges be modified to include a cost of gas component. The gas component to be used is one of three gas indexes. The noncompliance charges, with the relevant index, is shown in Table 8-6 of Exhibit 1.

ORA and SPURR/ABAG raised concerns regarding the noncompliance charge for CPGs in the event of an EFO. They question whether the noncompliance charge, with the index included, is an appropriate price to pay.

Aside from the higher price that a CPG will have to pay if it does not comply with an EFO, ORA and SPURR/ABAG have not rebutted PG&E's argument that adding a component which includes a gas index price will better reflect supply conditions and result in responsive behavior.

ORA's argument that the higher EFO noncompliance charge with the gas index component should not be considered because there is a correlation with the Winter Firm Reliability Requirement is not persuasive. PG&E's testimony regarding EFOs establishes sufficient reasons to add a gas index component to the noncompliance charges.

We will permit PG&E to use the gas index price in its noncompliance charges. As mentioned earlier, the core charge for an EFO shall be $50 plus the DCI.

Accordingly, we adopt PG&E's proposal that most of the noncompliance charges incorporate one of three relevant gas indexes.

We also authorize PG&E to use the noncompliance charges shown in Table 8-6 of Exhibit 1 for 2004, except for those noncompliance charges that are related to proposals that we do not adopt, or that we have changed the amount of the charge.

6. Anonymous Trading Platform Proposal

PG&E proposes to eliminate the electronic trading platform that was approved in D.00-05-049, and to credit back to the BCA $656,000 of the $700,000 that was authorized to implement the trading platform.⁴⁰

No other party submitted testimony or commented on PG&E's proposal.

Since no one expressed an interest in continuing with the development of a third party electronic trading platform, we adopt PG&E's proposal to eliminate the third party trading platform and services that was adopted as part of the settlement in D.00-05-049. As part of PG&E's proposal, PG&E shall credit back to the BCA the unused portion of the monies that were allocated to this project.