3. Core Brokerage Fee

3.1. Introduction

The core brokerage fee issue concerns the costs associated with the business functions that are necessary for procuring or purchasing natural gas for PG&E's core customers. The core brokerage fee is one of five cost components which make up PG&E's Schedule G-CP. Schedule G-CP represents the charge that PG&E's bundled gas customers pay for gas procurement services.

PG&E and SAT disagree on what business functions should be included in the core brokerage fee. The amount of the core brokerage fee is important because it is a cost factor that gas customers may take into account in deciding whether to take gas service from PG&E or from one of the competitive gas providers such as the SAT entities.²

The current core brokerage fee is $0.032 per decatherm (Dth), which remains in effect through December 31, 2010. This current core brokerage fee was agreed to as part of the settlement that was adopted in D.07-09-045.

In this proceeding, PG&E recommends that the core brokerage fee be lowered from the current rate to $0.0188 per Dth for the next cost allocation period.

SAT recommends that an interim core brokerage fee of $0.1347 per Dth, plus procurement personnel and direct overhead costs, be adopted.³ SAT recommends that this interim fee remain in place until an independent study is performed of the actual costs incurred by PG&E for all the business functions needed to provide gas supply to its core customers.

3.2. The Position of PG&E

PG&E proposes in Chapter 4 of Exhibit 39 to reduce the core brokerage fee component of Schedule G-CP from the current level of $0.032 per Dth to $0.0188 per Dth.

PG&E's proposed core brokerage fee is based on a core brokerage fee study that it undertook in response to the statement in D.07-09-045 that the core brokerage fee would be addressed in PG&E's cost allocation proceeding. The core gas procurement activities in PG&E's study consist of "non-commodity costs incurred by PG&E when purchasing gas for its core customers." (Ex. 1 at 4-9.) The core gas procurement activities in PG&E's study include portfolio management and assessment, supply nomination, contract administration, analysis and forecasting, transport scheduling, and trading. These core gas procurement activities are handled by PG&E's Core Gas Supply Department. In addition, PG&E's Market Risk Management Department provides risk management activities. Support functions for these activities include case management and tariff support from PG&E's Regulatory Relations Department, analytical support from its Integrated Resource Planning Department, and support from its Law, Information Technology, and Human Resources departments.

PG&E contends that its core brokerage fee study demonstrates that the actual cost of its core brokerage fee in 2007 and 2008 was $0.0166 per Dth. PG&E notes that this is 48% lower than the current core brokerage fee of $0.0320 per Dth, which was agreed to in the settlement agreement that was adopted by D.07-09-045. By escalating the 2008 core brokerage fee by the labor escalation factors, PG&E proposes a core brokerage fee of $0.0188 per Dth for this cost allocation period.

PG&E contends that a higher than justified core brokerage fee will make PG&E's current gas procurement costs for bundled core customers artificially higher than a core transport agent's brokerage related procurement costs. To core gas customers comparing the cost of taking gas from PG&E or from a core transport agent, this would make PG&E's rate higher than the core transport agent's rate.

PG&E also points out that if PG&E's core brokerage fee is used as a benchmark, that a higher than justified core brokerage fee will result in a higher than justified benchmark. PG&E contends that the use of a higher benchmark will lead to higher procurement costs for PG&E's core procurement customers, and higher procurement costs for customers who buy gas from a core transport agent.

PG&E believes that SAT's proposal is inappropriate and contrary to the history of the core brokerage fee. PG&E contends that the core brokerage fee has only included the costs related to procurement, i.e., the purchasing of gas. PG&E contends that SAT's proposal would incorrectly include costs which are not associated with the purchasing of natural gas, such as the cost of billing and collection.⁴ PG&E contends that SAT's proposal would expand the definition of the core brokerage fee to include the costs of "providing" or "delivering" natural gas. If SAT's proposal is adopted, PG&E asserts that the core brokerage fee and the costs of bundled service will increase, which will make gas service by PG&E less attractive to gas customers who are contemplating taking gas service from a core transport agent.

PG&E contends that SAT's proposal to expand the definition of the core brokerage fee is a self-serving attempt by the SAT entities to increase their profits and market share. Contrary to SAT's assertions, PG&E contends that there is no subsidy created by the core brokerage fee.

3.3. The Position of SAT

SAT's position is that the past settlements and decisions on PG&E's core brokerage fee only set the amount of the fee, and did not define what cost functions or activities should be included in the core brokerage fee. Since no settlement was reached in this proceeding on the amount of the core brokerage fee, SAT contends that the issue of whether additional costs should be included in the core brokerage fee remains an open question.

SAT notes that during the negotiations of the original Gas Accord settlement in 1996 and 1997, core transport agents such as SPURR, favored a core brokerage fee definition that included all of the costs necessary for PG&E to provide natural gas service to bundled core customers. SAT's testimony states that the "CTAs argued that the CBF [core brokerage fee] should include the costs of billing and customer service related to commodity supply --- since all CTAs must bear such costs --- while PG&E argued that billing and customer service costs should be recovered through non-bypassable transportation fees." (Ex. 48 at 5.)

SAT contends that in this proceeding, PG&E has ignored including certain costs into the core brokerage fee, and has presented an inadequate study of the costs. SAT also criticized the lack of experience of the PG&E witnesses to address concerns about the type of costs that competitive gas suppliers have, how customers assess their choices in the energy market, or the composition of a level, competitive playing field. SAT contends that PG&E should have included the costs for a variety of functions that are necessary for PG&E to sell commodity gas to core customers. In SAT's view, these functions include accounting, billing, customer service (bill inquiries due to high procurement price), and credit and collection costs related to PG&E's sales of commodity natural gas. SAT contends that all providers of commodity gas supply must perform these kinds of business functions, "such as enrolling new customers, managing customer information, procuring commodity supplies, billing customers, paying vendors, providing customer service and responses to procurement related customer inquiries, collecting payments from customers, accounting for revenue and expenses, managing cash, and handling customer terminations." (SAT Opening Brief at 5.)

SAT contends that PG&E's core brokerage fee calculation only included a portion of the business functions necessary for PG&E to sell commodity gas to core customers. By failing to include these other costs, SAT contends that PG&E's proposal fails to properly allocate costs and continues an ongoing subsidy of PG&E's bundled customers by customers of core transport agents in the gas transportation rate. According to SAT, this results in a PG&E commodity rate (Schedule G-CP) which is artificially low as compared to the rates offered by competing gas suppliers such as the SAT entities, and a transportation rate that is too high. SAT contends this sends an incorrect price signal to customers, distorts a customer's analysis of choosing a gas supplier, and provides a price advantage to PG&E who is the default service provider. In order to create a level playing field for all gas commodity suppliers, SAT contends that the costs of all business functions related to the gas purchase and sale function must be included in the core brokerage fee that is allocated to Schedule G-CP.

SAT argues that a subsidy will result if PG&E's calculation of the core brokerage fee is used. This subsidy comes about because a PG&E bundled customer and a customer of a core transport agent, who use the same amount of gas in the same time period, will pay the same amount in transportation rates. SAT contends, however, that the transportation rate that the core transport agent's customer pays includes cost recovery for all billing services by PG&E, for transportation service, and for commodity supply. Although the customer of the core transport agent is not being billed for the commodity by PG&E, the core transport agent's customer is still being billed as if it were a PG&E commodity customer because it must pay PG&E's billing service costs. Since the core transport agent's customer is paying for the billing service costs, SAT alleges that the rate charged to the bundled customer is lower than it should be, and that this amounts to a subsidy of PG&E's bundled customers by the customers of the core transport agents.

In order to establish an accurate core brokerage fee and a level playing field, SAT recommends that PG&E be required to submit to an independent study of all the cost elements that are necessary to provide commodity gas supply on the PG&E system. SAT contends these cost elements must include billing, collection, accounting, high bill inquiry, and customer service. SAT further recommends that the "study must be performed by an independent, qualified firm, with sufficient experience in the retail natural gas industry, and must be made available for scrutiny by the Commission, by market participants, and by the public." (Ex. 48 at 16.)

SAT recommends that an interim core brokerage fee of $0.1347 per Dth be adopted, plus the costs of procurement personnel and direct overhead, until this independent study can be completed. SAT arrived at this number by using the rate in PG&E's Schedule G-ESP as a proxy for the accounting, billing, and collection costs that SAT contends PG&E failed to include. SAT contends this is a reasonable proxy because this is the rate that PG&E charges all core procurement groups, except PG&E's own core procurement department, for consolidated PG&E billing services. Under Schedule G-ESP, the rate is $0.70 per service account per billing cycle. SAT contends that because PG&E's core procurement group is exempt from paying these billing, collection, and accounting costs, there is a market distortion of about $35 million per year in favor of PG&E and to the disadvantage of the core aggregators such as the SAT entities. SAT calculates that this results in an annual subsidy of $0.1347 per Dth for billing, collection, and related accounting services.

3.4. Discussion

3.4.1. Introduction

The core brokerage fee issue centers around what costs should be included within this fee. The core brokerage fee is a cost component of PG&E's Schedule G-CP. Schedule G-CP represents the gas procurement charges that PG&E's bundled core customers pay. As more costs are allocated to the core brokerage fee, there is a corresponding decrease in the transportation rate. Thus, if more costs are allocated to the core brokerage fee, the more competitive a competing gas supplier looks to a bundled core customer who is contemplating a switch. In this proceeding, SAT seeks to broaden the definition of the core brokerage fee to include billing, collection, and other costs, while PG&E seeks to continue the same kind of procurement-related costs that have been included in the core brokerage fee in the past.

3.4.2. Applicable Decisions and Code Sections

The starting point for our analysis is to examine the historical development of the core brokerage fee. In the first adopted settlement of what has now become known as the Gas Accord, D.97-08-055 (73 CPUC2d 754), the core brokerage fee was set at $0.024 per Dth. (73 CPUC2d at 830.) SAT takes the position that D.97-08-055 only established the amount of the core brokerage fee, and that the parties did not agree to a definition of the core brokerage fee.

PG&E points out that in section IV.H., the "Core Aggregation Regulatory Issues" of Appendix B to D.97-08-055, the Gas Accord Settlement Agreement provides in paragraph 1:

The PG&E core procurement brokerage fee will be set at $0.024/Dth and will be subject to balancing-account recovery. This fee will be reviewed when PG&E's market share drops to 80 percent." (73 CPUC2d at 830.)

Then in paragraph 3 of section IV.H. of Appendix B to D.97-08-055, the settlement agreement provides:

Billing and metering costs will remain bundled. PG&E will install additional metering at the request/expense of aggregators and their customers, and will provide a credit if PG&E equipment can be removed as a result. (73 CPUC2d at 830.)

The PG&E witnesses also contend that PG&E's cost elements for the core brokerage fee were described in the first Gas Accord settlement as "covering directly related embedded costs for supply planning, gas purchasing, supply nominations for transportation and storage injection/withdrawal, and legal, regulatory, and accounting activities related to gas procurement." (Ex. 39 at 4-9; See Ex. 41 at 5.) However, as pointed out in Exhibit 41 and Exhibit 48, these cost elements were not listed in D.97-08-055, but instead originated as "Appendices 2 and 3" to "The Report on the Gas Accord Settlement Agreement" dated May 10, 1996. Appendices 2 and 3 were prepared by the Core Procurement Advisory Group (CPAG) and the local distribution company (LDC)/End-User Issues Forum. In Appendices 2 and 3, under the sub-heading of "Core procurement brokerage costs," it states in part:

The CPUC, in Decision No. 95-07-048, ruled that the cost to PG&E of purchasing core gas supplies ("brokerage costs") should be unbundled from core transport rates in the then-pending BCAP decision. In PG&E's BCAP decision (Decision No. 95-12-053), the Commission set an interim core brokerage fee at 1.0 cent per decatherm, with unrecovered costs subject to balancing-account treatment. The BCAP decision also ordered PG&E to submit a cost study, on an marginal-cost basis, in its next BCAP, so that any change could become effective coincident with the unbundling of interstate transportation on January 1, 1998.

For the purpose of this settlement, the CPAG members agreed that it would be best to simply define a reasonable number, bounded by the aforementioned 1.0 cent per decatherm number and the 3.8 cents per decatherm figure currently in place for core-subscription customers, and to come to an agreement on the general kinds of costs that the number is intended to cover.

In the negotiations, the fee was set at 2.4 cents per decatherm, exactly splitting the difference between 1 cents and 3.8 cents. This fee is intended to cover directly-related embedded costs for the following functions: supply planning, gas purchasing, supply nominations for transportation and storage injection/withdrawal, and law, regulatory, and accounting activities related to gas procurement.

This figure probably exceeds the incremental cost to provide the service, which is likely less than 1.0 cent per decatherm. However, it does not include general corporate costs from parts of the Company indirectly related to the purchase of core gas supplies. Thus, it represents a reasonable compromise between the utility position (and Commission directive) favoring an incremental-cost approach and the supplier position favoring a more comprehensive embedded-cost approach. (Ex. 48, SPURR Exhibit A.)

The CPAG appendices were not included as part of the Gas Accord Settlement Agreement that was approved and attached to D.97-08-055 as Appendix B. (See 73 CPUC2d, Appendix B at 797.) However, the CPAG appendices were part of the five PG&E documents associated with A.96-08-043, in which the motion to adopt the Gas Accord Settlement Agreement was considered in and ultimately addressed in D.97-08-055. (See 73 CPUC2d, footnote 8 at 763 and 872, OP 4 at 795.)

PG&E points out that the decision in the core aggregation transportation (CAT) program supports PG&E's position that the core brokerage fee should consist of the costs of procuring or purchasing gas, as opposed to the costs of providing gas. In D.95-07-048 (60 CPUC2d 519), which addressed modifications to the CAT program, the Commission described how the joint petition to modify would unbundle core aggregation rates "so that customer-related services would be removed and a customer services fee would be paid only by core customers who purchase their gas supplies from the utility." (60 CPUC2d at 524, emphasis added.) In the footnote following this quote, the Commission stated "Customer service fees are distinguished from `brokerage fees' because the latter are only those costs related to purchasing the gas commodity. Customer service fees would cover a wider range of services such as energy conservation and usage information, billing and payment policies, meter reading, safety inspections, and carrying costs of storage gas." (60 CPUC2d at 534, emphasis added.)

Although the Commission denied the joint petition to modify, the Commission concluded that brokerage costs shall be unbundled from CAT rates to reflect the cost of gas procurement. (60 CPUC2d at 529, COL 2 at 532, OP 4 at 533; 63 CPUC2d 414 at 449.) The Commission stated in D.95-07-048:

In D.94-12-052, we adopted a core brokerage fee and associated ratemaking adjustments for SoCalGas [Southern California Gas Company]. We will direct PG&E and SDG&E [San Diego Gas & Electric Company] to propose and implement a core brokerage fee in their upcoming or pending BCAP [Biennial Cost Allocation Proceeding] proceedings. A determination of the appropriate core brokerage fee will require an underlying cost study. Such a cost study should be included as part of each utility's BCAP application. Consistent with the goal that the CAT program should promote efficient use of the gas system, our preliminary thinking is that the core brokerage fee should be based on the marginal cost of utility core procurement. In each BCAP, parties should address how their core brokerage fee is consistent with the efficient use of the gas system. (60 CPUC2d at 529, emphasis added.)

It is apparent from the above review of past Commission decisions that the core brokerage fee represents the costs associated with gas procurement/purchasing, and not the costs associated with customer service fees such as billing and payment policies, meter reading, and safety inspections.

In addition, if one reviews the origin of the rules for the CAT program in D.90-11-061 (38 CPUC2d 333) and D.91-02-040 (39 CPUC2d 360), the Commission clearly drew a distinction between commodity-related costs and the cost of transportation. In the adopted final rules for the CAT program, rule 5 states in part that "The transportation rate for each end-user facility served shall be the otherwise applicable core rate schedule for the specific facility minus the adopted core procurement portfolio price." (39 CPUC2d at 366, App. A at 371; See 38 CPUC2d at 336, App. A at 337.)

The distinction between the transportation rate, the gas procurement rate, and the core brokerage fee, was explained by the Commission in a cost allocation proceeding for SoCalGas. The Commission stated:

The basic concept behind the brokerage fee is that the utility incurs certain costs in performing its gas procurement function, which costs have traditionally been included in transportation rates rather than procurement rates. Since transport-only customers do not cause the utility to incur procurement costs, it is inequitable and inconsistent with cost causation principles to include procurement-related brokerage costs in the transport rate. (D.94-12-052 [58 CPUC2d at 338].)

The historical development of the core brokerage fee, and the Commission's distinction between brokerage fees and customer service fees also finds support in Public Utilities Code §§ 328, 328.1 and 328.2.⁵ These three code sections were added as a result of the restructuring of natural gas services.

Section 328 was first added by Chapter 401 of the Statutes of 1998, with an effective date of August 25, 1998. This version of § 328 allowed the Commission to investigate the issues associated with the restructuring of natural gas services, but prohibited the Commission from enacting any gas industry restructuring decisions prior to January 1, 2000, and from enforcing any natural gas restructuring decisions for core customers as considered in Rulemaking 98-01-011 after July 1, 1998.

Section 328 was revised by Chapter 909 of the Statutes of 1999. Chapter 909 also added §§ 328.1 and 328.2. In the Legislative Counsel's Digest to Chapter 909, it states in pertinent part:

Existing law permits the Public Utilities Commission to investigate the restructuring of natural gas services, as specified, but prohibits the commission, prior to January 1, 2000, from enacting any gas industry decisions and from enforcing any natural gas restructuring decisions for core customers as considered in Rulemaking 98-01-011 enacted after July 1, 1998, but prior to August 25, 1998.

This bill would repeal that provision, and, instead, would require the commission to require each gas corporation to provide bundled basic gas service, as defined, to all core customers in its service territory unless the customer chooses or contracts to have natural gas purchased and supplied by another entity. The bill would specify that a public utility gas corporation shall continue to be the exclusive provider of revenue cycle services, as defined, in its service territory, except as specified, and would require the commission to require the distribution rate to continue to include after-meter services, as defined.

Section 328, as revised by Chapter 909 of the Statutes of 1999 states:

The Legislature finds and declares both of the following:

(a) In order to ensure that all core customers of a gas corporation continue to receive safe basic gas service in a competitive market, each existing gas corporation should continue to provide this essential service.

(b) No customer should have to pay separate fees for utilizing services that protect public or customer safety.

Section 328.1 provides:

As used in this chapter, the following terms have the following meanings:

(a) "Basic gas service" includes transmission, storage for reliability of service, and distribution of natural gas, purchasing natural gas on behalf of a customer, revenue cycle services, and after-meter services.

(b) "Revenue cycle services" means metering services, billing the customer, collection, and related customer services.

(c) "After-meter services" includes, but is not limited to, leak investigation, inspecting customer piping and appliances, carbon monoxide investigation, pilot relighting, and high bill investigation.

(d) "Metering services" includes, but is not limited to, gas meter installation, meter maintenance, meter testing, collecting and processing consumption data, and all related services associated with the meter.

Section 328.2 states:

The commission shall require each gas corporation to provide bundled basic gas service to all core customers in its service territory unless the customer chooses or contracts to have natural gas purchased and supplied by another entity. A public utility gas corporation shall continue to be the exclusive provider of revenue cycle services to all customers in its service territory, except that an entity purchasing and supplying natural gas under the commission's existing core aggregation program may perform billing and collection services for its customers under the same terms as currently authorized by the commission, and except that a supplier of natural gas to noncore customers may perform billing and collection for natural gas supply for its customers. The gas corporation shall continue to calculate its charges for services provided by that corporation. If the commission establishes credits to be provided by the gas corporation to core aggregation or noncore customers who obtain billing or collection services from entities other than the gas corporation, the credit shall be equal to the billing and collection services costs actually avoided by the gas corporation. The commission shall require the distribution rate to continue to include after-meter services.

SAT argues that these three code sections do not restrict the Commission from allocating costs to the core brokerage fee, while PG&E argues that these statutes restrict the Commission and the gas utilities from any further unbundling of gas rates.

When these three code sections are read together, along with the remarks by the Legislative Counsel's Digest to Chapter 909 of the Statutes of 1999, we agree that the statutes support the outcome that billing and collection costs cannot be unbundled into the core brokerage fee. Under these statutory provisions, a gas customer can choose "to have natural gas purchased and supplied by another entity." (§ 328.2) The gas utility is to be the exclusive provider of revenue cycle services except that a core aggregator can perform billing and collection services for its customers. If the gas customer obtains billing services from the core aggregator instead of from the gas utility, § 328.2 provides that the credit to be provided by the gas utility to that customer "shall be equal to the billing and collection services costs actually avoided by the gas corporation."⁶

As defined by § 328.1(a), the term "basic gas service" includes, among other things, "purchasing natural gas on behalf of a customer," and "revenue cycle services." "Revenue cycle services" are defined in § 328.1(b) to mean "metering services, billing the customer, collection, and related customer services." It is clear from a reading of those two definitions that the Legislature intended to distinguish between the purchasing/procurement of natural gas on behalf of a customer, and revenue cycle services such as billing and collection services. As noted earlier, D.94-12-052 and D.95-07-048 removed the core brokerage fee from the transportation rate and included it in the procurement rate.

Although SAT seeks to include billing and collection costs, as well as other costs, as part of the core brokerage fee, it is clear from the discussion above that the core brokerage fee is made up of costs related to the procurement or purchasing of gas, and that billing and collection costs are part of the transportation rate and cannot be unbundled into the core brokerage fee. The billing costs that SAT seeks to include into the core brokerage fee are not procurement-related costs, but instead are recurring costs that are associated with revenue cycle services, i.e., customer service fees. As noted earlier, § 328.1, D.94-12-052 and D.95-07-048 classify revenue cycle services or customer service fees as part of the transportation cost rather than as a procurement-related cost.

SAT argues that since the settlement in this proceeding did not address the core brokerage fee, and because past Gas Accord settlements did not define the core brokerage fee, that the Commission is free to expand the definition of the core brokerage fee by including additional costs, such as billing and collection costs, into the core brokerage fee. SAT further argues that that since the purpose of the core brokerage fee is to facilitate competition between the utilities and competing gas suppliers, the core brokerage fee definition should be expanded.

We do not agree with SAT that the definition of the core brokerage fee should be expanded. First of all, as discussed earlier, the prior Commission decisions and § 328.1(a) clearly draw a distinction between procurement/purchasing-related costs and revenue cycle or customer services. These revenue cycle or customer services are included within the definition of basic gas service. Second, §§ 328.1 and 328.2 make clear that billing, collection, and related customer services are part of the revenue cycle services, and that revenue cycle services are separate and distinct from the costs of procuring or purchasing gas. Since revenue cycle services, such as billing and collection, are distinct from the costs of procuring or the purchasing of gas, and the core brokerage fee is part of the costs of procuring or the purchasing of gas, the billing and collection costs should not be unbundled from revenue cycle services and allocated to the core brokerage fee.

Nor are we persuaded by SAT's argument that a subsidy will result from limiting the core brokerage fee to procurement-related costs, and having billing and collection costs remain as part of the transportation rate. As we discussed earlier, the decisions and applicable code sections distinguish between revenue cycles services, such as billing and collection costs, and procurement-related costs. In addition, we agree with PG&E's point that as the default provider of revenue cycle services, its billing system must be ready to accommodate any customer who decides to return to PG&E for bundled core gas service.

Based on the above review of the applicable decisions, code sections, and the arguments of PG&E and SAT, we decline to adopt SAT's proposal to include billing and other costs as part of the core brokerage fee.

3.4.3. Adopted Core Brokerage Fee

That brings us to what the level of the core brokerage fee should be for the period beginning January 1, 2011 until PG&E's next cost allocation proceeding is resolved.

SAT proposes an interim core brokerage fee of $0.1347 per Dth be adopted until the results of the independent study are completed and adopted. SAT's interim core brokerage fee relies on PG&E's Schedule G-ESP as a proxy. Schedule G-ESP applies to those core transport agents who request that PG&E provide consolidated billing services on their behalf. Schedule G-ESP collects the costs associated with PG&E having to bill, collect, and account for the core transport agent's charges and PG&E's transportation charges.

As we discussed in section 3.4.2., the core brokerage fee excludes these kinds of billing and collection costs because they are not related to the cost of procuring or the purchasing of gas. Since the rates in Schedule G-ESP are directly related to the revenue cycle services of billing and collecting from customers, the use of Schedule G-ESP as a proxy for the core brokerage fee would be inappropriate. Accordingly, SAT's proposal to use an interim core brokerage fee of $0.1347 per Dth until an independent study of the cost elements that are necessary to provide commodity gas supply on the PG&E system is completed, should not be adopted.

PG&E's cost study results in a recommendation of $0.0188 per Dth for the core brokerage fee. This is a decrease from the current core brokerage fee of $0.032 per Dth, which was agreed to in the Gas Accord IV settlement and adopted in D.07-09-045. A huge disparity exists between PG&E's recommendation of $0.0188 per Dth, and SAT's recommendation for an interim core brokerage fee of $0.1347 per Dth.

SAT contends that PG&E's cost study is deficient because it excludes many of the costs that should have been included. SAT states:

PG&E's testimony includes only costs related to procurement personnel and their direct overhead. The procurement business unit, called the "Core Procurement Department," performs only a small fraction of the business functions necessary for PG&E to sell commodity gas to core customers. PG&E's testimony excludes costs for a variety of functions that are necessary for PG&E to sell commodity gas to core customers, such as accounting, billing, customer service (high bill inquiries due to high procurement price), and credit and collection costs related to PG&E's sales of commodity natural gas. For example, in order to sell commodity gas, PG&E must bill for that product. Nothing in PG&E's testimony, or in PG&E's responses to SPURR's data requests, indicates that gas commodity billing costs are included in the [core brokerage fee]. This topic was excluded from the study that PG&E did on costs related to the [core brokerage fee]. Just because PG&E decided to exclude costs from their study, does not mean that such costs should be excluded from the [core brokerage fee]. (Ex. 48 at 10.)

SAT's argument about PG&E's cost study is based on the cost functions that SAT believes "are necessary for PG&E to sell commodity gas to core customers...." However, as we discussed earlier, the core brokerage fee is related to the procurement or purchasing of the gas supply, and not the cost functions that are used to "sell" or supply gas to customers. The types of costs that SAT seeks to include in the cost study are revenue cycle services that are separate and distinct from the procurement/purchasing costs. Accordingly, we are not persuaded by SAT's argument that PG&E's cost study is deficient.

We do, however, find some merit in SAT's argument that the purpose of the core brokerage fee is to facilitate competition between the utility and the competing gas suppliers. The amount of the core brokerage fee is a factor that gas customers consider in deciding whether to take gas service from competing gas suppliers or from PG&E. PG&E's recommended core brokerage fee of $0.0188 per Dth is 41.25% lower than the current core brokerage fee of $0.032 per Dth, and is lower than the $0.024 per Dth core brokerage fee that was adopted in the first Gas Accord decision.

In order to encourage competition between PG&E and competing gas suppliers, we recognize an appropriate balance must be reached in setting the core brokerage fee. If the core brokerage fee is set too low, this will act as a deterrent for customers to switch to a competing gas supplier. If the core brokerage fee is set too high, this will encourage gas customers to switch to a competing gas supplier.

As shown in Figure 1 in Exhibit 41 and in Exhibit 45, there has been a large increase in the number of large commercial customers, as well as other customer groups, that have switched to competing gas suppliers. The large commercial customers use large volumes of gas. During the four-year time period from January 2006 to January 2010, the gas volumes that larger customers who have migrated to competing gas supplier use has grown substantially. During this four-year period of time, the core brokerage fee was set at $0.024 per Dth, and then increased to $0.032 per Dth in January 2008.

Based on the trends shown in Figure 1 of Exhibit 41, and Exhibit 45, if we adopt PG&E's recommended core brokerage fee amount of $0.0188 per Dth, one would expect to see a smaller increase in the number of gas customers switching to competing gas suppliers. If the core brokerage fee is maintained at $0.032 one would expect the steady increase in customer switches to competing gas suppliers to continue.

However, to encourage the continuing growth of competition between PG&E and competing gas suppliers, we will adopt a core brokerage fee of $0.025 per Dth. This amount is about mid-way between PG&E's recommended core brokerage fee, and the current core brokerage fee level of $0.032 per Dth, which has resulted in a steady growth of gas customers taking service from competing gas suppliers. The adoption of a core brokerage fee of $0.025 per Dth is reasonable, and will help maintain a competitive playing field for gas customers considering taking gas from a competing gas supplier.

PG&E should file an advice letter with the Energy Division under Tier 1 of General Order 96-B, with an effective date of January 1, 2011, to implement the adopted core brokerage fee component of PG&E's Schedule G-CP.

² Competitive gas providers are sometimes referred to in this decision as core transport agents or CTAs, or as core aggregators.

³ SAT had recommended an interim core brokerage fee of $0.128 per Dth in Exhibit 48, plus procurement personnel and direct overhead costs. This interim fee of $0.128 per Dth is different from SAT's current recommendation of $0.1347 per Dth because of the use of updated core throughput volumes and the number of bundled core accounts.

⁴ In addition to billing and collection costs, SAT seeks to include the costs of accounting, credit and collection, and customer service associated with bill inquiries due to high gas costs.

⁵ All code section references are to the Public Utilities Code.

⁶ If the core aggregator performs all of the billing and collection services, then it receives a credit through PG&E's Schedule G-CRED.