This section addresses PG&E's cost allocation and rate design proposals for backbone transmission, local transmission, storage, and transmission-level customer access charges. It also addresses the backbone-only rate proposal, and the segmentation of the electric generation class.
PG&E proposes to maintain the current Gas Accord cost allocation and rate design structure for 2004, as extended by D.02-08-070, along with PG&E's proposed changes to the current cost allocation and rate design. PG&E's proposed rates are set forth in Appendix 14-1 of Exhibit 3 (Tables 14.1-1 through 14.1-13), and are summarized in illustrative class average rates in Table 14-1 of Exhibit 3. PG&E's proposed rates for 2004 assume the adoption of PG&E's backbone, local transmission, transmission-level customer access, and storage rate proposals.
PG&E's bundled core customers pay backbone transmission and storage costs as part of their core procurement rate. Gas ESPs, noncore customers, and shippers delivering on and off-system, pay backbone charges and optional storage services separately to CGT. Local transmission and transmission-level customer access charges are included in core and noncore end-user transportation rates.
The end-user rate components such as distribution, and customer class components (e.g., public purpose programs, forecast period costs, and balancing accounts), are set in the GRC, BCAP, annual true-ups of balancing accounts, and other regulatory and legislative proceedings.
The issues regarding cost allocation and rate design center around the concerns of some customers that rates should reflect the costs of the facilities used to provide the services, without additional cost subsidies. Other parties have expressed concern over the cost-shifting effects of the various proposals. In addition, the threat of competitive bypass from proposed pipeline construction projects has resulted in proposals that seek to address the bypass issue.
The Gas Accord established a separate unbundled backbone transmission service for firm and as-available on-system and off-system transportation. The initial cost of service was based on the 1996 GRC-adopted based revenues, excluding Line 401. (73 CPUC2d at 820.) Line 401 costs were based on the initial $736 million pipeline expansion project cost that was approved in D.94-02-042. (73 CPUC2d at 820.)
For the Gas Accord, the costs were allocated to the various backbone service paths using the embedded costs of the facilities. For Line 400, costs were maintained on a separate vintage basis from Line 401 costs. Other backbone costs were allocated to each path based on a pro rata share of the firm design capacities of each path. (73 CPUC2d at 819-820.) Table 14-3 of Exhibit 3 shows the firm design capacities that were used to allocate the costs of the backbone to the various backbone paths during the Gas Accord.
The load factor used to set the backbone rates in the Gas Accord was 87.5%. Incremental Line 401 (Schedule G-XF) Redwood Path rates were designed using a load factor of 95%. (73 CPUC2d at 821.)
In the Gas Accord, core Redwood Path rates were based on vintage Line 400 cost of service. Noncore on-system Redwood Path rates were based on Line 400 and on a phase-in of between 203 and 380.6 MDth/d of Line 401 cost of service. Off-system Redwood Path rates were based on the incremental Line 401 cost of service and rates. (73 CPUC2d at 820.)
The rate design for the Silverado Path on-system was based on a partial allocation of costs from all backbone transmission paths and the common backbone component. The Silverado off-system rate was equal to the Line 401 off-system rate since it assumes Line 401 is used to provide the service. (73 CPUC2d at 820.)
The Gas Accord also established two-part (reservation and usage) firm annual rates under modified fixed variable (MFV) and straight fixed variable (SFV) rate design options. Seasonal two-part MFV and SFV rate options and volumetric as-available rates were designed based on 120% of the firm annual rate. (73 CPUC2d at 802, 841-845, 848.)
The Gas Accord also honored pre-existing contracts such as G-XF contracts. (73 CPUC2d at 800, 815-818.)
The Gas Accord backbone rates escalated at 2.5% annually, except for Line 401, which was accounted for in accordance with D.94-02-042, and except for certain agreed-upon Line 300 revenue requirements associated with the $42 million of NOx-related retrofits which were added to the Line 300 escalated revenues. Backbone rates were guaranteed through 2002, subject to z-factor adjustments. (73 CPUC2d at 822.) D.02-08-070 extended the 2002 rates through 2003.
PG&E proposes to continue the basic cost allocation and rate design structure of the Gas Accord65 with the modifications described below.
PG&E proposes a partial roll-in of the core Redwood Path vintage rate design. Under PG&E's proposal, core vintage Line 400 Redwood Path rates will be 20% rolled-in with noncore Redwood Path costs for 2004. According to PG&E, a partial 20% roll-in of the costs for the two lines would establish a Redwood Path rate that more closely reflects the way the services are used today while managing core customers concerns for rate stability.
PG&E proposes to design on-system Redwood Path rates using all available Redwood Path firm capacity that is not contracted for under Schedule G-XF, including the Line 401 expansion capacity. Under the Gas Accord, on-system (non-vintage) Redwood Path rates were designed using only 380.6 MDth/d of Line 401 capacity. (See Ex. 3, p. 14-9, Table 14-3.) PG&E contends that this proposed design of the Redwood Path rates is justified due to the historical and expected future use of Line 401 for on-system deliveries. Since all Redwood Path capacity will be used to design on-system rates, PG&E proposes that the Redwood Path off-system rate be set to equal the on-system rate.
Table 14.4 of Exhibit 3 summarizes the firm design capacity of the various backbone paths that PG&E proposes be used to allocate costs. That table is reproduced below in Table 5.66
PG&E proposes in Table 14-5 of Exhibit 3 to assign the vintage Redwood Path capacity total of 615.5 MDth/d to core retail and core wholesale customers as follows: core retail - 609; Alpine - 0.087; Coalinga - 0.609; Island Energy - 0.072; Palo Alto - 5.433; West Coast Gas (WCG) Castle - 0.072; WCG Mather - 0.227. The Gas Accord provides that capacity of up to 6.6 MDth/d is available on the Redwood Path for existing wholesale customers on behalf of their core load. (73 CPUC2d 808.)
PG&E's assignment of capacity to the core for non-vintage Redwood Path and Baja backbone capacity is to meet core customers' 1-in-10 year demand requirements, as proposed by PG&E.
Approximately 86.4 MDth/d of off-system and 5.4 MDth/d of on-system Line 401 capacity is contracted for under Schedule G-XF. G-XF rates will continue to be designed on an incremental basis, in accordance with D.94-02-042.
PG&E proposes in 2004 to design backbone rates using a system average load factor of 68.4%. This load factor is calculated by dividing the adjusted 2004 demand forecast (2184.926) by the net firm design capacity (3195.292), as shown in Table 14-6 of Exhibit 3. PG&E states that this lower load factor reflects the recent changes in gas and electric demand, in particular, conservation efforts and a slower economy. Since PG&E proposes to be at-risk for throughput and revenues on its backbone transmission system, the load factor of 68.4% provides PG&E with a reasonable opportunity to recover its backbone cost of service.
PG&E's backbone rates are contained in Appendix 14-1 of Exhibit 3, in Tables 14.1-3 through 14.1-9. These backbone rates are subject to PG&E's proposed contingency rate adjustment, as discussed later in this decision.
PG&E's storage facilities were primarily built to provide core reliability. For the first year of the Gas accord, approximately $5 million of storage costs were allocated to the load balancing service. The remaining storage cost of service was allocated 87.5% to the core and 12.5% to market storage services based on the pro rata share of inventory capacity assigned to each service.
Storage costs allocated to the core were initially bundled in all core transportation rates. The Gas OII Settlement Agreement in D.00-05-049 unbundled storage costs from core transportation rates, and offered pro rata shares of Core Firm Storage capacity to CPGs. Currently, PG&E's Core Procurement Department recovers the cost of its pro rata share of Core Firm Storage capacity in bundled core procurement rates. Gas ESPs serving core customers are offered a pro rata share of Core Firm Storage capacity with an option to reject a portion of their storage assignment. Gas ESPs pay a monthly storage charge under Schedule G-CFS - Core Firm Storage, based on their quantity of assigned storage.
Storage costs allocated to pipeline load balancing are bundled in all backbone transmission rates. A new self-balancing service option was established in the Gas OII Settlement Agreement. Customers or balancing agents who elect self-balancing on a daily basis can opt out of PG&E's monthly balancing program and receive a $0.005 per Dth credit from PG&E. If they elect to self-balance, their share of the balancing storage costs and capacity are assigned to CGT's market storage services.
The storage costs allocated to CGT's market storage services are used to set rates for firm, negotiable, and as-available storage, and parking and lending services. Rates for the market storage services are based on the costs of storage injection, inventory, and withdrawal. Firm storage rates include a capacity (injection and inventory) and a withdrawal reservation charge and volumetric rate. The fixed capacity and withdrawal costs are recovered through the reservation charges, and the variable capacity and withdrawal costs are recovered through volumetric rates.
Negotiated firm and as-available services are negotiable above a price floor representing PG&E's short-run marginal cost of providing the service and under a ceiling representing 100% of the cost of service. Negotiated firm rates may be one-part volumetric or two-part reservation and volumetric. Negotiated as-available storage injection and withdrawal rates are recovered through a volumetric rate only.
Parking and lending services are negotiated under a cost-based maximum charge. The maximum charge is based on the annual cost of cycling one decatherm of firm storage gas assuming a 214-day injection season (April 1-October 31) and 151-day withdrawal (November 1-March 31) season.
PG&E proposes only minor refinements to the cost allocation and rate design structure for storage-related costs as established in the Gas Accord, refined in the Gas OII Settlement Agreement (D.00-05-049), and as extended for 2003 in D.02-08-070. Storage costs will be allocated to storage subfunctions based on each subfunctions' annual injection, inventory and withdrawal cycling capacity. In addition to storage base revenues, gas and electric shrinkage costs are included in the total storage cost of service.
As part of the storage cost of service for 2004, PG&E has included the long-term costs of financing non-cycle working gas into rate base. According to PG&E, it is currently receiving the short-term interest rate on non-cycle working gas. For 2004, $80.5 million has been included in rate base for this purpose.
PG&E forecasts $63.6 million in storage costs for 2004. This storage cost of service will be allocated to the storage services (core firm, standard firm, and monthly balancing) based on their pro rata share of annual injection, inventory and withdrawal cycling capacity assigned to each service. Tables 14-8 and 14-9 of Exhibit 3 shows PG&E's assignments of storage capacities to each storage service for 2004, and the proposed allocation of storage costs to each storage service.
The Core Firm Storage rate will continue to be designed as a single monthly capacity charge based on the cost of core storage service. Schedule G-CFS will apply to gas ESPs and CPGs, including PG&E's Core Procurement Department, as discussed in the section on storage. The gas storage shrinkage has been unbundled from the backbone shrinkage factor, and will be applied Core Firm Storage injections.
PG&E proposes to simplify the firm standard storage rate design by combining the capacity and withdrawal reservation and usage charges into a single capacity charge. PG&E states that this rate design will better reflect the way in which capacity rights are provided to customers.
Core wholesale customers will have a one-time option to subscribe to Standard Firm Storage capacity. The wholesale customer must notify PG&E in writing prior to the 2004 storage open season. They will receive first priority from the storage capacity allocated to the Standard Firm Storage service.
PG&E proposes no changes to the cost allocation and rate design for negotiated firm or negotiated as-available storage services, and no changes for parking and lending services.
Gas storage shrinkage has been unbundled from the backbone shrinkage factor and will be applied to firm injection for Standard Firm Storage services.
The standard firm, negotiated firm, negotiated as-available, and parking and lending rates are presented in Appendix 14-1, Table 14.1-10.
Storage costs allocated to pipeline load balancing will continue to be bundled in all backbone transmission rates.
PG&E proposes to continue the self-balancing service option that was established in D.00-05-049, even though there has been little interest in this program. The self-balancing credit will still be based on 80% of the total storage balancing assets. Customers or balancing agents who elect self-balancing on a daily basis can opt out of PG&E's monthly balancing and receive a $0.011 per Dth credit, up from $0.005 per Dth today. For those who elect self-balancing, their share of the balancing storage costs and capacity are assigned to CGT's market storage services.
The self-balancing credit is presented in Appendix 14-1 of Exhibit 3 in Table 14.1-13.
The Gas Accord established two all-volumetric local transmission rates, one for core customers and one for noncore customers. The local transmission rate is paid by all on-system end users and is non-bypassable. (73 CPUC2d at 822, 852.) Local transmission costs were allocated to core and noncore customers using the cold year coincident peak month (i.e., January) marginal demand measure adopted in the 1995 BCAP, D.95-12-053. Average core and noncore local transmission rates were designed using the throughput adopted in the 1995 BCAP.
PG&E states that the cost of serving individual customers within the noncore customer class differs widely from customer to customer, and all customers within the class pay the same single average local transmission rate. Such a rate design results in significant cost subsidies being paid by certain large and/or well-situated customers (e.g., close to a backbone transmission line). This averaging of the local transmission rate has caused certain customers to seek backbone-only rates or other economic transportation service alternatives. If a backbone-only (i.e., end user backbone level service) rate structure is adopted, all other core and noncore customers who are not directly connected to backbone facilities will pay a larger share of the local transmission costs in their rates. That is, if a backbone-only rate structure is adopted, the local transmission costs that are currently assigned to customers connected to the backbone will have to be reallocated to the customers remaining on the local transmission system.
For 2004, PG&E proposes to continue the single average local transmission rate for core customers. PG&E's proposed local transmission rate for core retail is $ 0.419 per dth.67 (Ex. 3, Table 14.1-11.) PG&E also proposes that this core retail local transmission rate apply to core wholesale customers68 because they are provided the same level of APD reliability as PG&E's retail core customers. Wholesale customers, on behalf of their retail customers, also receive a pro rata share of the core's Redwood backbone capacity at core's vintage rates, and an optional pro rata share of the Core Firm Storage allocation.
For noncore customers, instead of a single average local transmission rate,69 PG&E proposes segmenting the noncore class into a four-tier rate design based on a customer's annual usage. PG&E views this as a first step in deaveraging the noncore local transmission rate.
Under PG&E's proposal, there would be four tiers of noncore customers. Tier 1 serves those customers with annual loads of less than 3 million therms. Tier 2 serves those customers with annual loads of 3 million therms to 49.9 million therms. Tier 3 serves those customers with annual loads of 50 to 124.9 million therms per year. Tier 4 serves those customers with annual loads of 125 million therms or more. PG&E's proposed 2004 local transmission rates are $ 0.201, 0.154, 0.150, and 0.075 per Dth for Tiers 1, 2, 3 and 4, respectively. (Ex. 3, Table 14.1-11.)
This noncore local transmission proposal is designed to discourage uneconomic bypass by substantially reducing local transmission rates for those customers who desire a backbone-only rate.
Since the beginning of the Gas Accord, several noncore customers have attempted to bypass PG&E's local transmission system. Today, approximately 26 customers are directly connected to backbone facilities. If a backbone-only rate structure was adopted, it is uncertain how much of the total noncore throughput would connect to the backbone to avoid local transmission rates. PG&E believes it could be substantial, given that Tier 3 and Tier 4 throughput totals over 700 MDth/d for only 18 customers.
If one assumes that 600 MDth/d of load connects directly to the backbone, local transmission rates for both core and noncore will increase as compared to the local transmission rates that PG&E has proposed. This is illustrated in Table 14-11 of Exhibit 3 at page 14-25. If local transmission rates increase under a backbone-only rate structure, it may become economic for additional customers to build directly to the backbone to avoid paying local transmission rates.
The customer access charge (CAC) recovers the costs of providing and maintaining a customer's service connection, including the service line, regulator, and meter.
The CAC revenue requirement was originally set in the GRCs as part of the distribution base revenues. The costs allocated to transmission-level customer classes were based on each classes' respective share of scaled customer marginal cost revenues adopted in the 1995 BCAP, D.95-12-053. Once these costs were allocated to transmission-level customers, and the rates set for the Gas Accord, the transmission-level costs were excluded from the distribution base revenue allocation in subsequent BCAPs. Since transmission-level CACs are now addressed in the Gas Accord structure proceedings, these charges were excluded from PG&E's 2003 GRC, A.02-11-017. D.02-08-070 extended the CAC through 2003.
Industrial transmission customers served under Schedule G-NT pay a six-tier monthly charge based on annual usage. Wholesale customers pay a customer-specific monthly charge.
At the beginning of the Gas Accord, the Schedule G-UEG served one customer, PG&E's Utility Electric Generation (UEG), who paid a fixed monthly CAC. To facilitate divestiture of the UEG facilities, an all-volumetric charge was adopted on an interim basis in the 1998 BCAP, D.98-06-055, for existing and divested UEG. Cogenerators paid an all-volumetric CAC, calculated on a 60-day lag to achieve rate parity with the UEG's rate.
For wholesale and industrial customers, PG&E proposes to continue the existing customer access rate design methodology based on an updated customer access cost of service.
For industrial customers, PG&E proposes to add two additional tiers to its existing six-tier structure. The additional tiers would be applicable to very large customers with Tier 7 serving annual loads from 60 million to 239.9 million therms and Tier 8 serving annual loads of 240 million therms and above. PG&E proposes to apply the same eight-tier industrial rate structure to the new proposed single electric generation class.
For wholesale customers, an updated CAC was developed for each wholesale customer.
PG&E's proposed CACs for industrial and wholesale customers are shown in Table 14.1-12 of Exhibit 3. Under PG&E's proposed CACs for industrial customers, the increased charge would range from $11.92 to $39,256.31. For wholesale customers, the proposed increases in customer access charges would range from $437.05 to $12,626.59.
The customer class charge collects the public purpose program costs for such things as the California Alternative Rates for Energy program, energy efficiency and low income energy efficiency, and customer energy efficiency, and forecast period costs and balancing account costs established in the GRCs, BCAPs, annual true-ups, and other regulatory or legislative proceedings. The customer class charge also collects costs established under the Catastrophic Event Memorandum Account. Customer class charge rate components will continue to be updated in the BCAPs and annual true-ups. Customer class charges are paid by all on-system end users.
PG&E proposes one change to the customer class charge. PG&E proposes to eliminate the cogeneration distribution shortfall account and to recover the distribution costs allocated to distribution-level customers served from transmission-level rate schedules through a distribution rate component in the customer class charge. This is discussed in the distribution rates section.
Under PG&E's current tariffs, noncore customers connected to distribution-level assets are eligible for transmission-level rates if their average historical gas use through a single meter meets the following two standards: (1) is greater than 3,000,000 therms per year for the previous three years, and (2) is greater than 2,500,000 therms in the most recent 12-month period. PG&E performs annual reviews each January to determine continued eligibility for transmission rates. Administering and monitoring compliance with the above criteria has become burdensome, ambiguous and confusing to customers.
PG&E proposes to simplify the transmission-level eligibility standard by removing the two-stage standard, and replacing it with a single standard of eligibility. Under the new criteria, distribution-level noncore customers will receive transportation service under transmission-level rates during any month when their historical 12-month usage is 3 million therms or higher. Eligibility is based on a customer's average monthly usage as defined in PG&E's Gas Rule 1.
This change will simplify the eligibility standards, and ensure that eligible customers will pay transmission-level rates during the first month they qualify, rather than waiting until the next year's annual review for qualification. According to PG&E, this proposal will not result in any cost shifts or rate impacts.
In D.98-06-073, a settlement regarding the treatment of distribution-level costs allocated to industrial transmission customers was adopted. The settlement allocated 50% of these distribution-level costs to shareholders, and the remaining 50% to other distribution-level customer classes for the remainder of the Gas Accord. D.02-08-070 extended this rate treatment through 2003.
For 2004 and thereafter, PG&E proposes to reestablish a distribution rate component in the customer class charge for the industrial transmission customer class. PG&E will recover these distribution costs directly from the industrial transmission customer class, rather than through a partial cost subsidy from all other distribution-level customer classes. This proposal will result in a slight increase in rates for industrial transmission customers and a slight decrease in rates for all remaining distribution-level customers.
Cogeneration customers situated on distribution-level facilities are also allocated a share of the distribution-level scaled marginal cost revenues from the BCAP. The Gas Accord decision removed the distribution rate component from these costs and collected the distribution costs from cogeneration and UEG end users through a cogeneration distribution shortfall rate component in the customer class charge.
For 2004, PG&E proposes to recover distribution revenues allocated to cogeneration customers from a distribution rate component in the customer class charge paid by cogeneration and electric generation customers, and eliminate the cogeneration shortfall account in the customer class charge. There is no rate impact from this proposal on any customer class.
In the Gas Accord, balancing account protection for noncore distribution revenues was removed. As a result, noncore distribution revenues were exposed to throughput risk. Core distribution revenues continue to be protected, which creates incentives to shift costs to noncore customers and to overstate noncore throughput forecasts in the BCAPs. Due to the migration of noncore customers to core, conservation, and a slower economy, PG&E has experienced a distribution revenue shortfall at its shareholders' expense. Also, noncore distribution loads are sensitive to fluctuations in weather.
PG&E proposes 100% balancing account protection for noncore distribution revenues. PG&E notes that in D.02-12-017, SoCalGas was granted 100% balancing account protection for noncore throughput revenue risk on distribution and local transmission revenues beginning in 2003.
When the Gas Accord began, PG&E's rate schedules serving generators were Schedule G-UEG and Schedule G-COG. Schedule G-UEG served only one customer, PG&E's UEG, which at the time operated seven gas-fired electric generation plants. Schedule G-COG served distribution and transmission-level cogeneration facilities and solar electric generation projects. In accordance with the rate parity provisions of Public Utilities Code §454.4,70 PG&E limits the volume of gas qualifying for G-COG to the lesser of: (1) the cogeneration gas allowance (CGA) for each kilowatt-hour of net electricity generation fueled by natural gas; or (2) the quantity of gas actually consumed in the cogeneration facility. Cogeneration volumes in excess of the CGA pay the customer's otherwise applicable rate.
The parity rule was applied during the Gas Accord in the following manner. Backbone transmission rate parity with UEG transportation contracts was provided to cogenerators for services from PG&E's transmission department on a path-specific and service-specific basis. (73 CPUC2d at 824.) End user parity was achieved by averaging the costs allocated to UEG and cogeneration customer classes so that each class paid the same per unit rate. The distribution costs allocated to distribution-level cogenerators were collected from all cogeneration and UEG end users. (73 CPUC2d at 826.)
During the Gas Accord period, Schedule G-UEG was renamed G-EG and was revised to serve transmission-level gas-fired generators including merchant power plants, independent power production facilities, municipalities, irrigation districts and joint power authorities, divested UEG, and PG&E's two remaining nondivested UEG plants.
In Resolution G-3242, and D.00-04-060, SoCalGas received approval for a single electric generation customer class serving all gas-fired generators, cogenerators, independent merchant plants and former utility electric generation plants. The class was further segmented by size (customers with usage of 3 million therms per year or less pay an additional distribution-leveldistribution-level component) and the collateral discount rule (CDR)71 and CGA were eliminated. The Commission stated in D.00-04-060 that the segmented rate proposal complied with § 454.4 because it treats all electric generators alike, regardless of their size, location, or present or former ownership. (D.00-04-060 at pp. 53-54.)
To align PG&E's electric generation rate design structure with changes resulting from electric industry restructuring and with SoCalGas and SDG&E's electric generation rate structure, PG&E proposes a single electric generation class serving utility electric generation, cogeneration, divested electric generation, municipalities, solar powered plants and merchant power plants. PG&E proposes to segment the class by transmission and distribution service levels, with customers using 3 million therms or greater served from the transmission-level rate, regardless of their service facilities. PG&E contends that segmented electric generation rates provide a more accurate price signal for new potential generator projects that are considering locating in PG&E's service territory, and would provide a consistent statewide rate design structure.
Under PG&E's proposal for 2004, distribution-level electric generation customers will pay a distribution rate component based on 25% of the distribution costs allocated to distribution-level electric generation and cogeneration customers. The remaining 75% of the distribution costs allocated to these customers will continue to be spread equally to all transmission and distribution-level electric generation customer volumes through the distribution rate component.
The electric generation class will be limited to customers with loads greater than 250,000 therms annually. Existing cogeneration and solar electric generation customers qualifying for service under Schedule G-COG, who use less than 250,000 therms annually, or are served under a core rate schedule for their use in excess of the CGA, as of December 31, 2002, will be grandfathered to Schedule G-EG for their loads serving generation. These cogeneration customers will be required to provide the same electric output information that is currently used to calculate their CGA. However, their loads qualifying for rates under Schedule G-EG will be based on the heat rates specified in Table 14-12 - Generator Heat Rates of Exhibit 3. All customers taking service from Schedule G-EG must purchase their gas from a third party supplier. Cogeneration customers who are served under the grandfathered provision above, will be given a one-time option to discontinue service under Schedule G-EG and convert to a core service for all of their use. Such customers will be restricted from the electric generation class from that point forward.
The distinction as a transmission or distribution electric generation customer is also consistent with PG&E's proposal to change the transmission-level eligibility criteria that has been mentioned earlier in this section of the decision.
PG&E proposes to eliminate the CGA in conjunction with measures to ensure that the volumes qualifying for the electric generation rate are limited to those used to generate electricity. PG&E recommends that all customers who qualify for the electric generation rate have a separate PG&E meter installed to measure gas use of the electric generation facilities, and that those facilities be monitored on a regular basis. Where separate metering is not economically feasible on existing generation facilities, gas volumes serving electric generators will be specifically measured using other gas metering devices and by the recorded net electric generation's output in kilowatt hours multiplied by the average heat rate for similarly sized electric generation facilities as shown in Table 14-12 of Exhibit 3. PG&E plans to update or modify the generator heat rates in Table 14-12 to reflect new technologies as they become available.
PG&E proposes to eliminate the CDR regarding cogenerator rate parity with UEG on backbone rates, end-user rates and rate discounts, and to eliminate the options for cogenerators to receive advance notice of UEG service elections. With a single electric generation class serving all electric generation customers, rate parity between certain UEG customers and cogenerator customers would be impossible to implement. Backbone transmission services will be offered on a path-specific and service-specific basis to all customers.
PG&E proposes to eliminate the distinctions in cost allocations and cost exemptions for the single electric generation class customers and require all customers to pay their pro rata equal-cents-per-therm share of franchise fees and Commission fees.72 Currently, UEGs are exempt from franchise fee surcharges under §§ 6350-6354, and are exempt from Commission fees. Under rate parity, the code sections extended the franchise fee exemption to cogenerators, PG&E's divested UEGs, municipalities, and merchant power plants pay franchise fees and Commission fees in their monthly bills. With a single electric generation class serving all gas-fired electric generation, the franchise fee provisions become difficult to apply, and the intent of parity under § 454.4 becomes less meaningful. The elimination of the cost exemptions for cogenerators and UEG would simplify cost allocation and rate design, and provide a level playing field for this customer class.
The proposed rates for the electric generation class which apply to Schedule G-EG are shown in Appendix 14-1 of Exhibit 3 in Table 14.1-2.
Other parties have proposed certain cost allocation and rate design changes. These proposals include the following: a backbone-level rate structure; 100% roll-in of Line 401 costs to the core; and increase the system load factor that PG&E uses, or use path-specific load factors.
CCC/Calpine support PG&E's proposal to roll-in the costs of Lines 400 and 401. However, they contend that current circumstances require that PG&E eliminate completely the core's preferential access to cheap, vintage Line 400 capacity, and that a single Redwood rate applicable to both core and noncore customers be adopted.
CCC/Calpine state that this roll-in issue should be decided now, rather than deferred to a future proceeding. Parties had the opportunity to litigate this issue during this proceeding, and parties presented evidence regarding Line 401.
CCC/Calpine assert that the energy crisis demonstrated that both core and noncore customers need, use and benefit from Line 401. According to the CCC/Calpine witness, the PG&E system was less constrained during the energy crisis than the SoCalGas system due to Line 401. Line 401 kept prices at Topock for delivery into the PG&E system significantly lower than Topock gas into the SoCalGas system. Even TURN conceded during cross-examination that the availability of Line 401 capacity during the energy crisis benefited customers by reducing prices at Topock. Line 401 also produces $4 million per year in compressor fuel savings for PG&E's core customers. Without Line 401, PG&E would have had to severely curtail noncore loads on its system, including electric generation customers.
CCC/Calpine point out that in D.97-08-055, the Commission stated that it would revisit the incremental rate treatment for Line 401 if it can be shown that Line 401 provides substantial customer benefits. CCC/Calpine assert that the benefits incurred by core gas customers as a result of the availability of Line 401 meets the Commission's substantial customer benefits standard. PG&E's witness also agreed that the standard for attributing the costs of Line 401 to core customers has been satisfied. (2 RT 130.)
PG&E admits that the core has benefited from Line 401, which justifies the roll-in of Line 401 costs. But to avoid too much of an upset to customers, only a roll-in of 20% is sought. CCC/Calpine contend that the Commission should take PG&E's proposal to its logical and appropriate end, and allow a full roll-in, or averaging, of Line 400 and 401 costs.
TURN's argument against a roll-in of Line 401 is that it "violates the Commission's policy regarding overbuilding beyond the system's needs and economic efficiency." (TURN, Opening Brief, p. 22.) CCC/Calpine assert that this argument is speculative, and is not based on any evidence in the record. CCC/Calpine contend that the issue of whether to roll-in the costs of Line 401 is not a matter of broad policy. Rather, it is a matter of whether benefits have been demonstrated, which CCC/Calpine contend have been shown. Those benefits should be reflected in core rates.
TURN contends that core customers should not have to subsidize Line 401 on the theory that electric customers receive reliable electricity as a result of gas transported over this line. CCC/Calpine are not asking electricity customers to pay twice for the same benefits, rather they are seeking to have core customers pay for the full benefit they receive from the use of Line 401. They contend that cost savings on the gas side results in lower rates for electric generation because production costs decrease. Any cost savings that noncore customers will enjoy as a result of core customers paying for 100% of their use of Line 401 will be passed onto electricity customers in the form of lower rates.
TURN also argues that the benefits to the core of Line 401 are, at best, indirect, and dwarfed by the benefits enjoyed by noncore customers. CCC/Calpine contend that TURN's witness admitted that the availability of Line 401 capacity during the energy crisis benefited customers by reducing prices at Topock. (7 RT at 707.) TURN also states that core customers purchase significant amounts of gas at the border. Thus, according to TURN's own argument, core customers should be paying something for this benefit.
CAPP proposes that the costs of Line 400 and Line 401 be fully rolled-in. CAPP contends that the statement in D.97-08-055 that before any roll-in of costs can occur, there must be substantial benefits to core customers, has been satisfied. The benefits of Line 401 include: sufficient gas in northern California during periods of unanticipated demand; the amelioration of the price effects of a shortfall of capacity at a time of historic high prices; the creation of a viable spot market for citygate purchases, which has contributed to the flexibility of PG&E's core procurement activities; and reduction in PG&E's compressor fuel use by 6.1 MMcf/d, a benefit of $10.2 million per year using a gas price of $4.50 per Dth. CAPP contends that none of these benefits were present prior to the Gas Accord. Without Line 401, Northern California would have experienced drastically higher prices.
CAPP submits that the only issue with respect to the treatment of the Line 401 costs is whether the roll-in should be restricted to 20% as PG&E proposes. CAPP contends that PG&E has not provided any justification for restricting the roll-in of costs to 20%. CAPP contends that the 20% figure appears to be an after-the-fact effort to create a rationale for this element of PG&E's proposal. CAPP asserts that limiting the roll-in to 20% is purely arbitrary and nonsensical given that core customers have received substantial benefits from this capacity.
With respect to ORA's argument against the roll-in of Line 401 costs, CAPP asserts that the record in this proceeding now includes extensive evidence of the actual operations of Line 401, and the substantial customer benefits that these facilities have had on the overall market and on core customers in Northern California.
In response to TURN's argument that the roll-in of Line 401 costs is contrary to Commission precedent, CAPP asserts that the decision made it conditional on the outcome of future evidentiary developments. The Commission identified "substantial benefits" as a reason for whether a roll-in of Line 401 costs would be appropriate. The record demonstrates that the benefits from Line 401 have been substantial.
CAPP asserts that TURN's argument that if Line 401 had not been built, that another company would have built a different pipeline, is speculative. Such speculation is of little value because it is unclear how much other capacity would have been built, or when. Instead the evidence shows the Line 401 benefited customers when there was an unanticipated surge in demand for gas in 2000-2001.
TURN cited a Commission report which concluded that the dramatic border price increases were not caused by inadequate natural gas infrastructure. CAPP points out, however, that the same report reinforces the point that the presence of Line 401 led to a lower Topock-into-PG&E price compared to the Topock-into-SoCalGas price, and that the Baja path was running at less than full capacity because PG&E had Line 401 available.
CAPP also refutes TURN's argument that even if Line 401 did put downward pressure on border gas prices, that the benefits primarily accrued to noncore customers. CAPP points out that such an argument is incorrect. PG&E's witness testified that PG&E's Core Procurement Department purchased about 745 MDth/d on average during the relevant time period, while PG&E holds about 600 MDth/d of interstate capacity coming out of Canada. A comparison of these two figures proves that PG&E's Core Procurement Department enjoys a direct benefit from a lower Topock price, as it cannot meet all of its demand from Canada-sourced supplies. As PG&E witness Gee said, "401 has brought additional supply into the marketplace in which all market participants, including core, has benefited from."
PG&E proposes a 20% roll-in of Line 401 costs to the core.
CCC/Calpine advocate that instead of a 20% roll-in of Line 401 costs, PG&E should completely eliminate the core's preferential access to cheap, vintaged Line 400 capacity, and should establish a single Redwood rate applicable to both core and noncore customers. The reasoning for the elimination of the vintaged path is that all customers, including the core, benefit from the availability of Line 401 capacity.
TURN recommends that the Commission retain vintaged Line 400 rates for core customers, and that no roll-in of Line 401 costs occur.
NCGC supports the full roll-in of Line 401 costs with Line 400 costs. TURN's position should be rejected. PG&E and CCC/Calpine have established that Line 401 benefits all customers.
NCGC points out that PG&E's core customers are paying a full rolled-in rate for transportation service on the PGT-Northwest system from Canada to the California-Oregon border. NCGC contends that if a full roll-in is appropriate for the Oregon and Washington segments of the Expansion Project, it is certainly appropriate for the California portion.
If the Commission decides to adopt PG&E's partial roll-in proposal, NCGC urges the Commission to direct that the phased roll-in be effected in increments of 20% over five years so that a full roll-in will be accomplished by the end of 2008. NCGC contends that the annual rate impact on the core each year would be negligible. An annual 20% roll-in of Line 401 and Line 400 will result in only a 0.8% increase in bundled core customer rates each year. An average residential customer using 50 therms per month would see a rate increase of only 30 cents per month (0.76%) for each year of the five-year phased roll-in period. Given the benefits that Line 401 has provided to core customers, NCGC contends that this small rate adjustment is justified.
NCGC asserts that by removing transportation rate differences that give a preference to one basin or supply point over another will promote gas-on-gas competition. NCGC believes it would be appropriate for the Commission to consider CAPP's recommendation for a full roll-in of all backbone facility costs and the development of a single postage stamp rate utilizing a single system-wide load factor.
ORA is opposed to PG&E's proposal to roll-in the costs of Line 401 to the core.
ORA contends that when PG&E was granted the CPCN to build Line 401, it was premised on the assurance that existing customers would not have to pay for the costs of Line 401.
In the Gas Accord decision, the Commission approved a partial roll-in of Line 401 to the noncore, but only because the noncore had agreed to it as part of the Gas Accord Settlement Agreement. The Commission also pointed out in D.97-08-055 that it would strongly disfavor any future PG&E request for a full roll-in of Line 401 costs if such a roll-in would increase either core or noncore rates. PG&E's proposed roll-in will result in substantial rate increases which affect both retail and wholesale core customers.
PG&E proposes to partially roll-in the costs of Line 401 into the core's vintaged rates. TURN opposes the roll-in of any Line 401 costs into core rates.
TURN contends that such proposals breach PG&E's past commitments regarding Line 401. TURN contends that nothing in the Gas Accord has relieved PG&E from its prior commitments with respect to assuming the risks of cost recovery of Line 401 and the protection of captive customers from those costs and risks.
PG&E applied for a CPCN to build Line 401 in A.89-04-033. The Commission granted the CPCN in D.90-12-119, stating that "No costs of the expansion will be allocated to PG&E's existing customers, except to the extent that PG&E itself is a customer of the Expansion Project." (D.90-12-119 at 37-38)
TURN points out that when the Commission approved the Gas Accord Settlement Agreement in D.97-08-055, the Commission noted that PG&E's application for a CPCN to build Line 401 "promised to insulate original system ratepayers from any risks and costs of Line 401." (73 CPUC2d at 772) The Gas Accord decision also stated that PG&E "took advantage of the Commission's `let the market decide' policy for new pipeline capacity, in exchange for assuming responsibility for associated costs and risks. [The Commission is] obligated to defend those customer protections vigorously. (73 CPUC2d at 773.)
TURN contends that the Commission recognized in the Gas Accord decision that the roll-in of Line 401 costs to the noncore was economically inefficient and violated principles of incremental ratemaking. However, the Commission approved the roll-in for noncore customers, and stated:
"only because noncore representatives have agreed to it.... Therefore, our finding that the Gas Accord is in the public interest is predicated on the fact that the core retail and core wholesale end users will continue to benefit from low, vintaged rates on Line 400 and will not have to pay for Line 401 costs. We would strongly disfavor any future PG&E request for a full roll-in of Line 401 costs if such roll-in would increase either core or noncore rates (absent an all-party settlement), whether such request occurred before or at the expiration of the Gas Accord." (73 CPUC2d at 782.)
The Commission warned that the approval of the Gas Accord would not stand as precedent in favor of rolled-in rates and approved the Gas Accord based on the fact that PG&E would not roll-in Line 401 rates to the core. (73 CPUC2d at 775.)
PG&E attempts to justify the Line 401 roll-in by describing the benefits that the core has received as a result of Line 401. TURN points out that when the Gas Accord was approved, it acknowledged that the core may receive small benefits from Line 401. (73 CPUC2d at 774.) TURN argues that these claimed benefits are at best indirect, and subject to dispute as to their magnitude. Also, any benefits to the core are dwarfed by those enjoyed by noncore customers.
To allow PG&E's partial roll-in of Line 401 would also violate the Commission's policy regarding overbuilding beyond the system's needs and economic efficiency. As TURN argued in the Gas Accord:
"allowing rolled-in ratemaking could undermine future market tests for new capacity in the gas pipeline industry and perhaps in other industries. To weaken `let the market decide' policies after construction of utility expansions could harm the Commission's credibility. If PG&E is now allowed to roll the cost of unnecessary assets into original system rates, then future market players might be tempted to deter competition by overbuilding new capacity, hoping the Commission will later shift the risks of undersubscription or underutilization back to captive customers. Utilities and their competitors would question the Commission's resolve in enforcing the assignment of risks and costs to the sponsors of new capacity." (73 CPUC2d at 773)
TURN points out that no advocate of the Line 401 roll-in addressed these issues of anticompetitiveness and preventing inefficient overbuilding.
Granting PG&E's proposal to roll-in 20% of the Line 401 costs will also erode the Commission's credibility and send a message that the Commission does not stand by its decisions, nor does it hold parties accountable for their sworn statements. (See 73 CPUC2d at 779.) TURN contends that the Commission should not deprive core customers of the promises made to them when authorization was sought to construct Line 401.
TURN asserts that the arguments of CCC/Calpine rely on a faulty historical premise. If PG&E has not constructed Line 401, TURN contends that it is likely that another pipeline company would have built a competing pipeline to supply Northern California. (See 39 CPUC2d 69, 118; Ex. 4, p. 3-11.) One cannot rewrite history by simply assuming that the benefits of additional capacity would not have existed absent the building of Line 401.
The CCC/Calpine witness spent considerable time discussing the fact that without Line 401's capacity, there would have been electric blackouts in Northern California due to curtailments. Since residential electric customers are often PG&E core gas customers, they directly benefit from Line 401. TURN contends that this argument assumes that residential ratepayers should have to pay twice for the same benefit, just because they take gas and electric service. TURN asserts that there is no policy rationale for charging core gas ratepayers for providing reliable gas service to electric generators. PG&E's electric ratepayers will have paid for whatever benefits they received from Line 401 in their electric rates. There is no justification for charging them again as gas ratepayers for those same benefits.
TURN also contends that there is no direct causal link between having the core pay for 20% or 100% of Line 401 capacity and reliable electric service. Line 401 capacity reduces the chances of gas diversion curtailment for all noncore customers. There is no reason why core customers should have to pay to reduce the potential of diversions for industrial noncore customers. In the event of a diversion, core customers would have to pay a significant penalty if noncore gas is diverted.
TURN also contends that the CCC/Calpine witness' conclusion that Line 401 reduced the gas prices at the southern California border are speculative. First of all, this argument ignores that if Line 401 had not been built, an alternative pipeline would have been built. Second, there is little factual foundation for the argument that the difference between PG&E-Topock and SoCalGas-Topock prices was caused by greater constraints on the SoCalGas system. The Commission staff's "California Natural Gas Infrastructure Outlook, 2002-2006" report concluded that the dramatic border price increases were not caused by inadequate natural gas infrastructure, but by market manipulation and insufficient storage injection by noncore customers. (Report, pp. 25-30.)
TURN asserts that there is substantial information in the record that conclusively indicates that other factors were more direct causes of the price differentials. TURN points out that no party analyzed the impact of upstream market manipulation on the El Paso system on the PG&E-Topock and SoCalGas-Topock prices. The Commission has maintained in D.02-07-037 at pp. 6 and 7 that the deliberate withholding of capacity and market manipulation by El Paso and its marketing affiliate contributed significantly to gas price increases. (D.02-07-037 at 6-7.) The parties also did not analyze the effect of fraudulent price reporting or market manipulation, or the temporary lifting of the price cap on the secondary market under FERC Order 637 on gas prices. TURN asserts that one cannot conclude that the simple presence of slack capacity on the PG&E was responsible for the large disparity in prices between PG&E-Topock and SoCalGas-Topock.
Even if one assumes that the capacity on Line 401 placed downward pressure on border prices is true, TURN asserts that any resulting benefit flowed to those customers who either purchase gas at the border or citygate, or who purchase gas at prices indexed to border prices. TURN points out that it is primarily noncore customers who buy their gas supplies at the border or citygate. PG&E's core customers use interstate capacity in order to purchase gas at the producing basins. The core would purchase, at maximum, about 40% of its gas at the border during the three peak winter months. On an annualized basis, that is less than 20% of the core's gas needs.
TURN contends that PG&E's noncore customers (or their marketers) would have been the primary beneficiaries of the price difference between PG&E-Topock and SoCalGas-Topock. The fact that core customers also obtained some benefit does not lead to the conclusion that the core should pay for the costs of Line 401.
TURN contends that another major flaw with the CCC/Calpine's analysis is that the PG&E and SoCalGas systems are inherently different in design. The SoCalGas system is "storage-rich," so a greater amount of peak demand is met through storage withdrawals rather than flowing supplies. During the energy crisis period, SoCalGas' storage system went into winter with record low levels of gas in storage, primarily due to almost no injections into storage by noncore customers during the summer of 2000. In contrast, the PG&E system relies to a greater extent on flowing supplies to meet peak demand.
TURN contends that PG&E has not explained how the citygate market has benefited the core, and there is little basis for concluding that the core received any major benefit from the citygate market. Even if it did exist, the core purchased only 17 Bcf at the citygate in 2002, out of a normal annual demand in 2004 of 292 Bcf (only about 6% of demand) which is hardly a significant amount.
TURN also argues that a roll-in of Line 401 costs may not benefit PG&E's noncore customers. TURN asserts that most of the holders of interstate capacity on the PG&E system are marketers, not PG&E's noncore customers. A noncore customer who buys gas at the citygate from a marketer will pay a market price, not a cost-based rate. TURN asserts that a reduction in the cost of one of several potential transportation paths may not translate into a lower market price at the citygate at all, but rather it may result in increased profits for the marketer who delivers over that path. Such a result is not in the best interests of California consumers.
TURN contends that if core customers require service over Line 401, that they will pay the associated costs. If Canadian gas is more economic than Southwest gas, the core could utilize Line 401 interruptible capacity and pay the applicable tariff rate. If core does not use Line 401, it should not pay. That was the original bargain behind Line 401.
TURN also notes that those in favor of the Line 401 roll-in rely on the phrase that "only a showing of substantial customer benefit can overcome the allocation of Line 401 costs." (73 CPUC2d 773.) TURN contends this phrase was taken out of context, and that the entire passage must be considered.
Another justification that the proponents use is that a 20% roll-in of Line 401 costs to the core will only increase core bundled rates by only .8%. (Ex. 4, p. 14-19, fn. 7.) However, when you add the increase of $0.006 per therm by the forecasted core throughput of 294,537 MDth for 2004, that increase amounts to $17.67 million. TURN points out that since others are pushing for a full roll-in, the 20% roll-in would just be the beginning. The approval of any of the roll-in proposals would increase the magnitude of financial hardship on core customers. This burden would be further magnified if PG&E's proposal to increase the local transmission cost allocation to the core is increased by 40.5%. (See Ex. 76.)
TURN contends that its position has been clear and consistent over the roll-in of Line 401 costs. TURN supports full regulation of bundled utility service whenever possible. But once certain large customers are allowed to strike their own deals, the financial bargains struck at that time must be maintained so that the residential and small commercial customers are not left holding the bag.
PG&E proposes a Redwood path rate design for core and noncore customers that reflects a partial roll-in of all Redwood path capacity and costs, except for contracts under Schedule G-XF. Core Redwood path rates would include a 20% roll-in of Line 401 costs for 2004. This 20% roll-in would moderate the impact on core customers, while moving toward a reduction of the large disparity between the rates paid by core and noncore customers for the same Redwood path service. Schedule G-XF contracts would continue to be priced based on the incremental Line 401 Pipeline Expansion Project cost of service as required by D.94-02-042.
PG&E points out that parties that benefit from the vintaged Line 400 rates oppose PG&E's proposal. The parties who represent noncore customers do not believe that the 20% roll-in goes far enough to reduce the core/noncore rate disparity because they believe the core benefits from Line 401. PG&E contends that its 20%proposal is a balanced approach.
PG&E asserts that the core receives a "substantial customer benefit" from Line 401. During the 2000 to 2001 period, the capacity on Line 401 alleviated high gas and electric prices in Northern California. Without Line 401, PG&E asserts that PG&E's system would have become constrained and customers would have faced much higher prices. Also, Line 401 and the Redwood path provided access to lower-priced Canadian gas. As a result of the price advantages for Canadian gas, the Redwood path, including Line 401, was highly utilized throughout the Gas Accord period. Table 3-2 of Exhibit 4 shows that utilization of the Redwood path averaged over 90% from mid-1998 to mid-2002.
PG&E points out that the citygate market has become much more liquid since the beginning of the Gas Accord. Line 401 brings additional supply to the market, which benefits all participants, including core customers. Without the capacity provided by Line 401, PG&E contends that the same citygate purchases would not be available.
PG&E contends that contrary to TURN's argument, the Commission did not grant core a "vested right" to vintage-priced Line 400 capacity. PG&E says that Commission policy has been, and continues to be, that those who benefit should pay their share of costs. PG&E asserts that Line 401 has been used at high load factors, which clearly demonstrates its value to the California market. In addition, new pipeline capacity continues to be built which indicates a demand for interstate pipeline capacity even beyond that provided by the PG&E expansion project.
Responding to TURN's argument that another interstate pipeline equivalent to Line 401 would have been built if Line 401 was not, is unsupported and contradicted by the evidence. PG&E showed that had Line 401 not been built, it is unlikely that as much alternate capacity would have been built. As recently as 1998 and 1999, there was substantial slack capacity in the system.
PG&E also states that Line 401 capacity has helped moderate costs for PG&E's customers, both gas and electric, and has reduced Northern California's exposure to problems on the El Paso system and at the California border. PG&E also states the record contains evidence that Line 401 has ensured that there are sufficient gas supplies to Northern California during time periods of unanticipated demand. Line 401 has also ameliorated the price effects of a shortfall of capacity at a time of historic high prices. Line 401 has also brought about the creation of a viable spot market for citygate purchases, and thus contributed greatly to the flexibility of PG&E in its core procurement activities. None of these benefits were present at the time the Gas Accord was initially approved by the Commission.
In an attempt to downplay the benefits resulting from the capacity provided by Line 401, TURN ignores the effect of the connection between intrastate load factors and gas prices. PG&E explained the relationship between pipeline utilization and constraints, and price differentials. The fact that prices rise when pipelines are constrained is a fact that is well established. PG&E also demonstrated that the PG&E system was generally unconstrained and did not contribute appreciably to price increases beyond border prices (at Malin and PG&E Topock). PG&E also explained that the SoCal-Topock price, and the price differential between PG&E-Topock and SoCal-Topock, reflect constraints on the intrastate SoCalGas system. Both PG&E and CCC/Calpine presented evidence that the SoCalGas system was highly constrained in 2000-2001. Without Line 401, PG&E says that one can only imagine how much higher prices in Northern California would have been.
PG&E asserts that PG&E and CCC/Calpine have shown that Line 401 has benefited core customers, but core is not paying for any of these costs.
PG&E also argues that in D.97-08-055, the Commission departed from the methodology set in D.94-12-058 by adopting partially rolled-in rates and the use of a system wide load factor for Line 401.
PG&E proposes a 20% roll-in of Line 401 costs, while CCC/Calpine and others favor a full roll-in of Line 401 costs.
PG&E's 20% roll-in would result in 2004 Redwood path rates of $0.176 per Dth for the core and $0.329 per Dth for the noncore. In comparison, the 2003 Redwood Path rates for the core and noncore are $0.125 and $0.269, respectively. TURN estimates that a 20% roll-in of Line 401 will cost core ratepayers $17.67 million in 2004. PG&E's witness acknowledged that the proposal for a 20% roll-in is just the beginning of a movement toward a full roll-in of Line 401 costs to the core. (9 RT 913-914.)
TURN contends that the Commission's prior decisions regarding Line 401 placed the cost of the project on PG&E. PG&E and the others who favor a roll-in, contend that they have demonstrated that the core has received "substantial customer benefits" from Line 401. The term "substantial customer benefits" or substantial benefits originated in the Gas Accord decision, D.97-08-055 (73 CPUC2d at 773.) Thus, our analysis of whether PG&E should be permitted to roll-in some or all of the costs of Line 401 begins with the Gas Accord decision.
As part of the Gas Accord Settlement Agreement, noncore customers agreed to a partial roll-in of Line 401 costs. Throughout the decision, the Commission mentioned the roll-in of these costs. PG&E and the proponents of the roll-in contend that the sentence referring to substantial customer benefits opened the door in this proceeding to the roll-in of Line 401 costs to the core. The sentence which the proponents of the roll-in rely on come from the following paragraph in section 5.3 of the decision, which is entitled "Features Opposing Approval" of the Gas Accord Settlement Agreement. (73 CPUC2d at 769, 771.) That paragraph reads:
"Second, rolled-in rate treatment for Line 401 and the proposed path-specific unbundling scheme would be inefficient and contrary to incremental ratemaking principles. Loss of economic inefficiency is built into the averaging process because shippers would not face the costs of individual pipeline assets. In A.89-04-033, PG&E promised to insulate original system ratepayers from any risks and costs of Line 401. The Commission confirmed that none of the costs of Line 401 would be allocated to original system ratepayers. When PG&E determined the scale and timing of the expansion project, it took advantage of the Commission's `let the market decide' policy for new pipeline capacity, in exchange for assuming responsibility for associated costs and risks. We are obligated to defend those customer protections vigorously. Only a showing of substantial customer benefits can overcome the allocation of Line 401 costs to customers that do not need or desire Line 401 capacity. Path-specific unbundling would further obscure the incremental nature of Line 401." (73 CPUCd 772-773, footnotes omitted.)
We agree with TURN that one must read the reference to substantial customer benefits in context. In section 5.3 of the Gas Accord decision, the Commission was addressing the features of the Gas Accord settlement which did not favor approval. Section 5.2 of the decision addressed the features of the settlement in favor of its approval. Thus, the substantial customer benefits reference was to the noncore's willingness in the Gas Accord settlement to a partial roll-in of Line 401 costs. This is made clear in several passages in section 5.4, the "Conclusion" of the Gas Accord discussion.
In section 5.4, the Commission stated that "Increased costs associated with partial roll-in of Line 400 and Line 401 costs will be borne by noncore customers that freely entered into the settlement." (73 CPUC2d 774.) Two paragraphs later, the decision states in part:
"We are also concerned that the Gas Accord has not provided enough unbundling and that parties may attempt to improperly cite our approval of the Gas Accord as a precedent in favor of rolled-in rates (when our policies continue to be in favor of incremental rates) or that parties will claim that the Gas Accord resolved numerous issue which were never specifically addressed by the Gas Accord. Rather than reject the Gas Accord in light of these concerns, we believe that the much better course is to approve the Gas Accord in light of its improvement over PG&E's present rates, to narrowly interpret the Gas Accord and our order approving the Gas Accord so that it will not limit our ability to further address PG&E's conflicts of interest and unbundling issues, to clarify our policies and various ambiguities in the Gas Accord so that parties will not misinterpret this decision...." (73 CPUC2d 774.)
Toward the end of section 5.4, the decision states:
"In our discussion below, we also make it crystal clear that our approval of the Gas Accord cannot be cited as a precedent in favor of rolled-in rates...." (73 CPUC2d 775.)
All of the passages in section 5.4 of D.97-08-055 make clear that the Commission's policy is in favor of incremental rates, and that the approval of the Gas Accord Settlement Agreement "cannot be cited as a precedent in favor of rolled-in rates."
Then in section 6.3.1 of the Gas Accord decision, in a section entitled "Rolled-In Rates," the Commission stated:
"Although we are approving the Gas Accord, we remain concerned that the partially rolled-in rates for Line 400 and Line 401 are contrary to our incremental ratemaking principles. PG&E was authorized to build Line 401 based upon its pledge to utilize incremental rates, and PG&E assured us at that time that PG&E's existing customers would not have to pay for Line 401 costs. Approval of partially rolled-in rates for noncore customers is reasonable here, but only because noncore representatives have agreed to it in the Gas Accord, presumably in return for other benefits. Full roll-in of Line 401 costs would increase core rates and would significantly conflict with our policies. However, the Gas Accord does not provide for fully rolled-in rates; it protects core retail and core wholesale ratepayers from the unjustifiable increase in rates which would result from the rolled-in rates. Therefore, our finding that the Gas Accord is in the public interest is predicated on the fact that the core retail and core wholesale customers will continue to benefit from low, vintaged rates on Line 400 and will not have to pay for Line 401 costs. We would strongly disfavor any future PG&E request for full roll-in of Line 401 costs if such roll-in would increase either core or noncore rates (absent an all-party settlement), whether such a request occurred before or at the expiration of the Gas Accord." (73 CPUC2d at 782, original italics.)
Thus, the Gas Accord Settlement Agreement was adopted with the express understanding that "core retail and core wholesale customers will continue to benefit from low, vintaged rates on Line 400 and will not have to pay for Line 401 costs." The Gas Accord decision also expressed a strong disfavor for any future request for a full roll-in of Line 401 costs if such a roll-in increases core or noncore rates.
The incremental ratemaking treatment of Line 401 first began when PG&E received a CPCN for the project in D.90-12-119 (39 CPUC2d 69).73 In the section addressing risk allocation for the project, the Commission stated:
"Until further Commission action, we find that the project sponsors are PG&E's shareholders, and it is PG&E's shareholders and Expansion shippers, not the existing ratepayers, that bear the risk of the Expansion Project's failure to recover its revenue requirement. The shift of risk to existing ratepayers may occur, if at all, only if the Commission finds that the Expansion Project's contribution to margin would constitute a financial benefit sufficient to overcome the Project's potential burden of revenue underrecovery. However, we conclusively find that none of the costs of the Expansion Project may be recovered in any non-Expansion Project rate proceeding, advice letter or accounting mechanism." (39 CPUC2d at 81.)
Further in the CPCN decision, in which the Commission discussed the economic justification for the project, the Commission stated:
"We note that PG&E has affirmatively stated that it will not seek to recover any Expansion Project costs (other than transportation costs) from its existing ratepayers. Such assurance is also implied from the applicant's intent to collect Expansion costs from only the project sponsors and Expansion shippers. We confirm as a condition of issuance of this CPCN that PG&E's existing ratepayers should not bear any of the cost of the Expansion. This segregation of costs, risk, and benefit is appropriate at this time, particularly since PG&E has not yet executed Firm Transportation Agreements with the Expansion shippers. ... We will revisit this issue in the Expansion Project's first general rate case, when concrete evidence of shipper participation, the Expansion's costs and rates, and the potential contribution to margin will be available. (39 CPUC2d at 120.)
In Finding of Fact 103, Conclusions of Law 7 and 31, and Ordering Paragraphs 3 and 14.h. of D.90-12-119, the risk of recovery was placed on PG&E's shareholders and the expansion shippers, pending an allocation of the risk of revenue recovery as between ratepayers and shareholders, which was to be determined in a general rate case application for Line 401.
In D.94-02-042 (53 CPUC2d 215), the decision which addressed the rates for Line 401, the Commission assigned "all risks of undersubcription, and most of the risks of underutilization" of Line 401 to PG&E's shareholders. The remaining risks of underutilization was placed on the expansion shippers. (53 CPUC2d at 230.) D.94-02-042 also found that the risk of recovery of Line 401's project costs should be borne by PG&E's shareholders. (53 CPUC2d at 230, 249.)74
PG&E and CCC/Calpine contend that the core has realized substantial benefits from Line 401, and therefore a roll-in of the costs of Line 401 should be permitted. However, the starting point in deciding whether a roll-in proposal should be adopted is that such proposals are strongly disfavored unless there is an all-party settlement. (73 CPUCd 782.) The benefits that a particular customer class may have received is only one factor to consider. As noted in the Gas Accord decision, the impact of a roll-in on core or noncore rates is the major concern.
Although PG&E's proposal is to only roll-in 20% of the costs of Line 401 in 2004, such a roll-in would increase both core and noncore rates as shown in Tables 14.1-3 and 14.1-4 of Exhibit 3. The effect on the core alone in 2004 amounts to approximately $17.7 million. PG&E's proposal, if approved, is only the tip of the iceberg, in that it will seek to roll-in even more of the Line 401 costs in future years. Some of the other parties already advocate a full roll-in for 2004. If such proposals are adopted, the cumulative impact on the core will amount to a substantial amount. The Gas Accord decision clearly contemplates that a full roll-in of Line 401 costs is contrary to the Commission's incremental ratemaking principles that existing customers should not have to pay for Line 401 costs.
There was also testimony in this proceeding that the price of gas is likely to remain high in the foreseeable future. In addition, PG&E recently announced that higher winter gas bills are expected because of the high cost of gas. When high gas costs are factored into the monthly bill of gas customers, together with the cost of a partial or full roll-in of Line 401 costs, core customers will experience severe rate shock.
One option that the Gas Accord recognized for a possible roll-in is if there was an "all-party settlement." However, none of the parties have proposed such a settlement for 2004. Without a settlement wherein core customers willingly agree to a roll-in of Line 401 costs, the express policy is to strongly disfavor a roll-in proposal if such a roll-in increases rates to the core or noncore. Since there is a $17.7 million impact for 2004 on the core, the roll-in proposals of PG&E and others must be disfavored.
Based on the regulatory history of Line 401, the commitments made by the Commission and PG&E, and our prior decisions, in combination with the additional costs that core customers will be saddled with if we adopt a partial, or eventual full roll-in of Line 401 costs, we are compelled to abide by our prior decisions. These considerations outweigh any substantial benefits that the core may have received as a result of Line 401.75
In exchange for the right to build Line 401, PG&E expressly agreed to undertake the risk associated with the costs of Line 401. The rate case for Line 401 confirmed that ratemaking treatment, and the Gas Accord continued the incremental ratemaking treatment of Line 401, except as agreed to by the noncore customers in the Gas Accord Settlement Agreement. PG&E should be held to its part of the bargain.
To renege on our prior commitments regarding Line 401 will undermine our regulatory authority by opening the door to the utilities to seek more favorable ratemaking treatment after a decision, or in the case of Line 401, a series of decisions, have been made.
Based on the above discussion, PG&E's proposal to roll-in 20% of the Line 401 costs to the core is not adopted. In addition, the proposals of the other parties for a full roll-in of Line 401 costs is not adopted. The rates for 2004 shall not include any roll-in of costs on Line 401 to the core.
PG&E proposes to design its backbone rates using a system load factor of 68.4%. This load factor was calculated by dividing PG&E's system throughput forecast for 2004 by its system design capacity, with various adjustments for SMUD's equity capacity and firm off-system contracts. PG&E then uses this load factor to calculate all path-specific backbone rates, except for G-XF rates, which assume a 100% load factor.
Since PG&E is assuming the risk in 2004 for noncore local transmission and backbone revenues, CCC/Calpine assert that PG&E has dramatically understated its throughput and load factor forecasts. PG&E stands to benefit from the throughput and load factor that is in excess of its forecasts.
CCC/Calpine assert that PG&E's proposed calculation of its system load factor underestimates PG&E's ability to earn revenues from its backbone services. The witness for CCC/Calpine explained that under the Gas Accord structure, PG&E does not charge for backbone service solely on the basis of throughput. PG&E sells firm capacity, for which the utility collects demand charges regardless of whether the capacity is fully used. Many shippers pay demand charges in exchange for the assurance that they will have firm capacity when they need it. However, some firm shippers do not fully utilize their capacity, even though they have paid for that space through the demand charge. CCC/Calpine contend that a proper calculation of the system load factor should include the revenue associated with the demand charges.
In addition, PG&E's calculation of the system load factor must also account for the revenues associated with PG&E's marketing of as-available service, which results from the unused firm capacity that shippers have paid for through demand charges, but have not used. PG&E can charge up to 120% of the annual firm tariff rate for as-available service.
CCC/Calpine, CMTA, and Mirant propose to establish backbone rates in 2004 using a recommended system load factor of 81.3%. The calculation of the 81.3% load factor is explained at page 41, and shown in Table 9, of Exhibit 6. The system load factor of 81.3% is based on (1) PG&E's expected firm capacity sales in 2003, which is assumed to continue at a similar level in 2004; (2) an assumption that firm noncore shipper will use their firm capacity at an 88% load factor, based on the utilization rate for firm capacity during the Gas Accord; (3) as-available usage for the remaining volumes of the throughput forecast of CCC/Calpine, including the higher demand from electric generation; and (4) 120% weighting of as-available throughput to reflect the higher as-available rate.
CCC/Calpine point out that Table 8 of Exhibit 6 demonstrates that PG&E's system load factor based on throughput was 82% for the Gas Accord I period, and the load factor based on the sale of firm and as-available capacity was 93%.
Although TURN recommends a load factor for the backbone system of approximately 75%, TURN's witness agreed that the CCC/Calpine witness' method was the "next best approach."
CMTA contends that PG&E's load factor of 68.4% underestimates expected system throughput. CMTA contends that by using a lower system throughput figure, this underestimates PG&E's ability to recover its backbone revenue requirement, and its ability to earn revenues from selling backbone services.
CMTA states that backbone rates should use a load factor that is based on the percentage of its backbone services that PG&E will sell in 2004, instead of just throughput. CMTA supports the load factor of 81.3% that CCC/Calpine witness Beach developed.
Although CAPP supports the continued use of the basic framework of the Gas Accord structure, CAPP believes there are some deficiencies with the current structure. Most notable is the use of a rate design that has not efficiently or equitably allocated the costs of PG&E's backbone transmission paths to the users of those paths, which results in significant cross-subsidization among the transportation paths. CAPP contends that in order for Northern California to enjoy the ample supply of Canadian gas, the rates for backbone transportation service must accurately reflect the cost and utilization of the facilities, i.e., there must be cost-based transmission rates.
CAPP proposes a rate design proposal comprised of three elements. The first element is to implement a consistent, harmonized approach to the design of rates for the two principal backbone transmission paths, the Baja and Redwood paths. CAPP proposes that there be a path-specific allocation of costs, matched by the use of path-specific load factors to derive rates. The second element is the full integration, or roll-in, of the Line 400 and 401 costs.76 CAPP contends that a full roll-in will reflect the actual impact of those facilities. The third element, in the event path-specific load factors are not used, is to use a postage stamp rate with a higher overall load factor to derive PG&E's rates.
Under the current rate design, path-specific capital costs are utilized to design path-specific rates using a system-wide average load factor. CAPP contends that a path-specific load factor must be used if path-specific costs are used to develop rates. CAPP, therefore, recommends a cost-based rate design for each of the two major supply transportation routes. The alternative is to adopt system-wide average costs with system-wide average throughput, i.e., a postage stamp backbone rate.
CAPP points out that the Redwood Path includes the relative higher capital costs associated with Line 401. Those costs are higher due to the fact that it is much newer, and therefore less depreciated than the Baja Path facilities. CAPP also points out that the load factor on Line 401 is based on the use of a systemwide load factor. However, the Redwood Path is highly utilized, which generates a higher system average load factor. Since the Redwood Path has a much higher utilization rate than the other paths on the California transmission system, the rates for service on the Redwood Path should be relatively lower, all other factors being equal.
Using illustrative 2004 costs and projections of path-specific throughput from the 2002 California Gas Report (CGR), CAPP contends that Baja rates should be 39 cents/Dth higher than Redwood rates if both path-specific costs and throughput were employed in the rate design. Under PG&E's proposal, utilizing path-specific costs and system-wide average throughput, PG&E's Redwood Path rates would produce a 10.8 cents/Dth premium for Redwood service compared to Baja. CAPP contends that PG&E's proposed rate design favors Southwest gas supply, and Redwood Path shippers subsidize the costs of Baja Path service. This cross-subsidization can be eliminated by using path-based load factors.
CAPP's primary recommendation is to use path-specific load factors. For the Redwood Path and Baja Path, CAPP recommends path-specific load factors of 93% and 55%, respectively. For the Silverado and Mission paths, CAPP recommends a path-specific load factor of 84%.
CAPP's proposal would reverse the Redwood Path differential from a premium to a 6 cents/Dth discount. Under the CAPP proposal, path-based rates would incorporate a multi-year average load factor for each of the various paths.
PG&E recommends that CAPP's proposal to use path-specific load factors be rejected because the rates resulting from the CAPP proposal would increase costs to California end-use customers by raising the Topock transport rate $0.055 Dth higher than PG&E's proposed Topock rate. CAPP contends that PG&E's argument assumes that Topock is usually the marginal supply for gas transported to Northern California. CAPP contends that it is no longer factually correct or reasonable to assume that Topock is or will remain the marginal source of supply into Northern California. CAPP points out that Exhibit 13 shows that Malin has been the marginal supply 43% of the time since the Gas Accord has been in effect.
TURN opposes CAPP's proposal to employ path-specific load factors for computing Baja and Redwood transmission rates because TURN asserts it will result in highly unstable rates. CAPP contends that its proposal used load factor figures which incorporated a range of different operating conditions and over a wide period. Such an approach dampens the effects of variability in usage patterns, and generates rates that are stable. CAPP points out that a system-wide load factor is the sum of the path-specific load factors. Thus, any instability that affects path-specific load factors, also relate to the system-wide load factor as well.
CAPP contends that PG&E's load factor forecast for 2004 of 68.4% is grossly understated, and should not be treated as a credible figure for ratemaking purposes. If PG&E's forecast is adopted, this will allow PG&E to overcollect revenues.
CAPP asserts that the actual system utilization during the Gas Accord has exceeded PG&E's 68.4% load factor. Third party forecasts project system utilization for PG&E at a significantly higher level. For example, the California Energy Commission's December 2002 publication entitled "Natural Gas Supply and Infrastructure Assessment," forecasts throughput of 2,546 MMcf/d for 2004, which results in a load factor of 75%. According to PG&E, the CEC's forecast is considered conservative based on the track record of CEC in its forecasts of system throughput.
CAPP also asserts that PG&E's argument that off-system throughput will fall below historical levels in 2004 is not supported by PG&E's own observation that the historical price spreads between Malin and Topock are expected to continue. CAPP asserts that these price spreads drive the transportation market for off-system capacity.
In the event the Commission does not approve CAPP's path-specific rate design proposal, CAPP recommends that a single, system-wide postage stamp rate be adopted in 2004, with a 79% load factor. The completely rolled-in postage stamp rate would be $0.23 per Dth.
CAPP's load factor of 79% takes into account the fact that shippers that subscribe to firm backbone service can pay for capacity on a straight-fixed variable rate design, but do not utilize capacity at full contract volumes. To the extent that PG&E is able to sell as-available service from capacity that has been sold as firm service under the straight fixed variable rate design, the pipeline is compensated twice for the sale of such volumes.
PG&E criticizes CAPP's use of a 79% load factor. CAPP asserts that PG&E's argument relies on two false premises. The first premise that PG&E relies on is that because of the advent of combined cycle generating units, this has resulted in lower gas consumption. CAPP points out that to the extent that this has been the case, then the consumption data for the period in which that technology has been in place will already incorporate this development. Thus, CAPP's approach did not ignore this change in electrical generation technology from 1998 to 2002, the period when this technology is supposed to have begun, because CAPP used these demand numbers for that historical period.
The other premise that PG&E uses to criticize CAPP's load factor is that CAPP only used data from five years, which according to PG&E did not give the widest possible range of historical and expected market conditions. CAPP asserts that the data from 1998 to 2002 is the most relevant because that is when the market operated in an unbundled environment. Unbundling simply was not in place for the periods prior to 1998.
PG&E's design of backbone rates is based on a system load factor of 68.4%, which is far below the 87.5% load factor in the Gas Accord settlement. PG&E's lower system load factor supposedly "reflects the recent changes in gas and electric demand, primarily reflecting conservation efforts and a slower economy." (Ex. 3, p. 14-15.)
Mirant contends that PG&E has failed to justify the use of a lower system load factor. As pointed out by the witness for CCC/Calpine, PG&E's past forecasts have underestimated actual electric generator demand. Also, PG&E's estimate of off-system throughput is understated. Mirant recommends that the CCC/Calpine witness' recommendation for an electric generator/cogeneration demand forecast of 930 MDth/d, and an off-system throughput forecast of 298 MDth/d, be adopted.
The testimony of the CCC/Calpine witness also challenged PG&E's proposal to set rates based solely on a throughput-based system load factor. Beach noted that PG&E sells firm and as-available backbone services, and does not charge rates solely for volumes of throughput. Mirant supports the system average load factor of 81.3%, instead of PG&E's proposed factor of 68.4%. TURN witness Florio considered the 81.3% load factor proposal to be the next best approach. TURN also agreed with the CCC/Calpine witness' recommendation for a higher electric generator throughput.
PG&E proposes to design rates on the basis of a forecasted system load factor of 68.4%. PG&E's low load factor is due, in large part, to the low electric generator throughput projected by PG&E on the basis of an assumption about new power plants outside of PG&E's service territory.
NCGC points out that PG&E's system load factor is substantially below the 87.5% load factor assumption that is currently used for designing backbone rates. NCGC urges that the projected load factor proposed by PG&E be revised to reflect any revision in an updated electric generator throughput forecast. NCGC witness Pretto stated that a reduced system load factor could become a self-fulfilling prophecy by causing higher transportation rates, which could cause reduce electric generator throughput in PG&E's service territory.
NCGC is concerned about PG&E's proposed 68.4% load factor because it is inconsistent with historical experience. During the first four years of the Gas Accord, the Redwood and Baja paths operated at a combined capacity factor of 81%, 79%, 88% and 91%, respectively. (See Ex. 1, p. A4-5.) During the fourth year (March 1, 2001 through February 28, 2002) the combined unused capacity on these paths was only 9%, or 265 Mdth/d. The Redwood path was utilized at an especially heavy load factor. Scheduled volumes on the Redwood path equaled 97% of firm capacity in the first and second years of the Gas Accord, 100% in the third year, and 95% in the fourth year. PG&E's throughput forecast of 68.4% for 2004 is inconsistent with the historical experience of the Gas Accord.
NCGC states that CCC/Calpine, CMTA, and Mirant propose adjusting PG&E's load factor to reflect demand-charge based sales of firm backbone capacity. NCGC agrees that since demand charges were paid for the capacity, the demand charge revenues should be considered in calculating the load factor. NCGC also contends that the revenues from modified fixed variable (MFV) contracts, and revenues from straight fixed variable contracts, should be considered in calculating the load factor as well. If a customer takes firm capacity under an MFV rate but fails to use the capacity, it would be improper to calculate the backbone load factor and rate as though the capacity generated no revenues.
NCGC also favors CAPP's proposal for a postage stamp rate. CAPP noted that the least defensible feature of the Gas Accord backbone rate design was the asymmetrical use of path-specific costs in combination with a system-wide average load factor to develop path-specific rates. NCGC states that there has been a substantial shift in supply basin and pricing relationships. Given today's market structure, and a full roll-in of rates, NCGC believes that a postage stamp rate would benefit all customers by facilitating gas-on-gas competition between Southwest and Canadian supply basins.
PG&E's proposal to reduce the load factor on the backbone system from 87.5% to 68.4% is perplexing to SMUD because it has been requesting for quite some time for PG&E to sell more pipeline capacity to SMUD. If PG&E expects the pipeline to be so underutilized, SMUD is willing to pay over book value for additional backbone capacity. SMUD recommends that the Commission either adopt a load factor based on the volume of capacity sold, instead of PG&E's proposed load factor reduction based on projected throughput, or order PG&E to sell surplus backbone capacity to SMUD.
PG&E proposes to design backbone rates based on a projected system load factor of 68.4%. Although setting rates based on projected throughput is typical ratemaking practice, TURN contends that such practice should not apply in a situation such as this, where PG&E has formally accepted the risk of undersubscription and underutilization of Line 401.
In the first Expansion Project rate case for Line 401, A.92-12-043, the parties and the then-Commissioners debated the scope of risks that PG&E undertook when it elected to construct the Expansion Project. While a bare majority of the commissioners decided that PG&E had not accepted the risk of stranded costs resulting from the construction of Line 401, all of the commissioners agreed that, without question, PG&E had accepted the risks of undersubscription and underutilization associated with Line 401. Firm service rates for Line 401 were set based on a 95% load factor to reflect that assumption of risk by the project sponsor. (D.94-12-058, p. 9)
In the Gas Accord settlement, TURN asserts that the load factor of 87.5% reflected the parties' positions on PG&E's assumption of risk of the undersubscription and underutilization of its facilities.
TURN points out that PG&E is at risk for all of its backbone transmission costs, but the use of PG&E's system load factor, which is based solely on expected usage, ignores PG&E's prior commitments, and removes the risk of overbuilding and the underutilization that PG&E undertook. To resolve this, TURN witness Florio recommends the use of an adjusted system load factor that imputes 95% utilization of the expansion project, while assuming a throughput-based load factor for the remainder of the system. A single system-wide adjusted load factor would then be used to set actual backbone rates for each of the paths, as was done in the Gas Accord. TURN's adjusted system load factor is calculated at 75.7%.77 TURN recommends that the Commission adopt a single system-wide load factor of at least 75.7% for the purpose of setting rates for backbone transmission. TURN points out that the CCC/Calpine derivation of the system load factor of 81.3% is similar to the approach taken by Florio to arrive at the 75.7% system load factor.
The CAPP witness advocates the use of path-specific load factors, rather than an overall system load factor, for setting various path rates. TURN recommends that the proposal be rejected, and that a single system-wide load factor be used. TURN contends that any attempt to base path-specific rates on assumed future throughput levels would produce highly unstable rates, unless the initial forecast were left in place even as conditions change. TURN asserts that no one can say with any certainty that one supply area will continue to be more attractive. Locking in rates with path-specific load factors would tend to stifle, rather than promote, competition among gas supply regions.
CCC/Calpine propose that a load factor of 81.3% be adopted. PG&E asserts that this load factor fails to adjust for a reduction in off-system delivery of 66.5 MDth, and fails to adjust the unused firm capacity for 76.6 MDth/d which represents the volumetric component of the MFV capacity. In addition, the CCC/Calpine load factor overstates the electric generator demand forecast. If these adjustments are made, PG&E asserts that the proposed load factor of CCC/Calpine would more closely align with PG&E's proposed 68.4% load factor.
PG&E also asserts that the proposal of CCC/Calpine to calculate a system load factor based on expected revenues from backbone services is impractical, given the variety of service options PG&E offers to customers. Since the majority of backbone revenues may continue to be recovered on a volumetric basis, the risks of revenue volatility require a throughput based load factor.
PG&E points out that CAPP's path-specific load factor would result in a Topock rate that is $.055/Dth higher than PG&E's proposed Topock rate. PG&E contends that CAPP's proposed path-specific load factor is likely to increase costs to California consumers by increasing the transportation rate on the marginal path, the Baja Path. PG&E recommends that CAPP's path-specific load factor be rejected.
PG&E contends that TURN's proposal to bifurcate the load factor to design a portion of the Redwood path rates at 95% is without merit. PG&E says the record lacks the evidence to justify a bifurcated load factor calculation for on-system Redwood path rates.
PG&E proposes to design backbone rates using the system average load factor, using the 2004 demand forecast with certain adjustments, and divided by the firm design capacity. This results in a 68.4% load factor. PG&E proposes to exclude from the electric generator demand forecast 45 MDth/d of SMUD equity and 101 MDth/d of load served by third party private pipelines. PG&E also proposes to include a backbone throughput adjustment of 45.9 MDth/d to account for premiums and discounts on backbone transmission.
PG&E's lower load factor for 2004 reflects the recent charges in gas demand, resulting primarily from conservation efforts, a sluggish economy, and lower electric generator demand. PG&E asserts that its backbone load factor proposal represents a reasonable balance of risks and rewards, and sends the appropriate pricing signals to the market. Given PG&E's rate design, and the low expected level of capacity subscription in 2004, a system throughput based load factor is the only practical and reasonable method to design firm backbone rates. The Commission should adopt PG&E's proposal.
The forecast of gas throughput is a key element in the calculation of PG&E's gas transportation rates. The most contested elements of PG&E's 2004 throughput forecast in this proceeding are the forecasts of electric generator gas demand, which impacts both backbone and local transmission rates, and off-system throughput, which impacts backbone rates. PG&E's backbone system load factor is also in dispute, which affects backbone rates. The demand forecast of electric generator and off-system deliveries have been discussed earlier in this decision.
In the Gas Accord Settlement Agreement, a load factor of 87.5% was agreed to, which was used to calculate the firm annual on-system backbone transmission charges. As-available rates, and firm seasonal capacity charges were based on the firm annual on-system backbone charges. The Malin to off-system firm rates were calculated using incremental Line 401 costs and a 95% load factor. (73 CPUC2d at 821.)
PG&E and the other parties have come up with four different ways of calculating the load factor.
PG&E's load factor of 68.4% was developed using PG&E's adjusted demand forecast of 2,184.926 divided by the total (3195.292) of the net firm design capacities of each path, as shown in Table 14.4 of Exhibit 3.
The use of the net firm capacity of 3195.292 as the denominator for the load factor is a departure from the design capacities used in the Gas Accord. In the Gas Accord, costs were allocated to each path based on a pro rata share of the firm design capacities of each path. As shown in Table 14-3 of Exhibit 3, for Line 401, only 380.6 MDth/d was used to design on-system (non-vintage) 2002 Redwood Path rates. In contrast, PG&E proposes to use 870.1 MDth/d of Line 401 capacity to design the 2004 on-system Redwood Path rates. A portion of the 870.1 MDth/d comes from the recent Line 401 expansion capacity, while the rest comes from the remaining capacity on Line 401.
Using PG&E's adjusted demand forecast of 2184.926 and the denominator of 3195.292, PG&E's calculation of the load factor is 68.4%. If PG&E's adjusted demand forecast of 2184.926 is divided by a denominator of 2759.6, the load factor would be 79.2%.
The second load factor proposal is sponsored by CCC/Calpine, CMTA, and Mirant. They recommend the adoption of a load factor of 81.3%, as shown in Table 9 of Exhibit 6. This load factor is based on the percentage of the backbone services that PG&E is expected to sell in 2004. This load factor also accounts for the higher electric generator forecast that the CCC/Calpine witness Beach recommends.
The third load factor proposal is sponsored by CAPP. CAPP's primary recommendation is to establish path-specific rates, including a single Redwood rate applicable to both core and noncore customers. CAPP proposes that if its proposal for path-specific rates is adopted, the load factor on the Redwood Path should be 93%, a 55% load factor for the Baja Path, and for the Silverado and Mission paths a load factor of 84%. CAPP's derivation of the load factors is set forth in Table 1 of Exhibit 30.
If the Commission does not adopt CAPP's proposal for path-specific rates, CAPP's secondary recommendation is that the Commission approve a rolled-in postage stamp rate, i.e., a single average rate for all paths, using a load factor of 79%. The 79% takes into account the marketing of backbone services during the Gas Accord period, and is based upon a total demand forecast of 2367 MDth/d, and a denominator of 2987.78 Under this secondary proposal, the single average rate would be $0.23 per Dth.
The fourth load factor proposal is sponsored by TURN. TURN recommends that a load factor of 75.7% or greater be adopted. TURN's load factor proposes to adjust the usage on Line 401 to reflect the risk of undersubscription and underutilization that PG&E had agreed to when Line 401 was built. In D.94-12-058 (58 CPUC2d 417), firm service rates for Line 401 were set based on a 95% load factor to reflect the assumption of the risk by PG&E in constructing Line 401. In the Gas Accord, the load factor of 87.5% was agreed to by the parties and adopted. TURN contends that the 87.5% reflected, among other things, the assumption of the risk by PG&E.
If PG&E is allowed to use a system load factor based solely on expected usage, TURN contends that this would remove the risk of overbuilding and underutilization that PG&E undertook when Line 401 was built. To reflect this risk, TURN proposes that Line 401 usage be adjusted by imputing 95% utilization of the Line 401 Expansion Project, while assuming an adjusted throughput-based load factor for the rest of the system. The adjusted load factor would be used to set actual backbone rates for each of the paths.
To derive PG&E's adjusted load factor, several steps are involved. First, TURN would use the difference between the 95% utilization and the load factor resulting from the adjusted demand forecast divided by the total net firm capacity number of 3195.292, and multiply that difference by the net firm capacity of Line 401 of 875.463.79 Second, the product resulting from the multiplication would then be added to the adjusted demand forecast. And third, that sum would then be divided by the total net firm capacity of 3195.292 to arrive at the adjusted load factor. The adjusted load factor would then be used for setting the backbone rates.
In reviewing the demand forecasts and the different methods of calculating the load factor, it is apparent that the load factor we adopt will affect PG&E's ability to recover the adopted revenue requirement. As parties point out, PG&E prefers a lower load factor because it allows more costs to be spread over a smaller amount of throughput. Other things being equal, a lower load factor means higher rates. If PG&E is able to recover its revenue requirement, any revenues in excess of the revenue requirement benefits its shareholders since PG&E is at risk for any under-recovery or over-recovery. Other parties prefer a higher load factor so that costs can be spread over a larger amount of throughput, thus lowering rates. A higher load factor makes it more difficult for PG&E to recover its revenue requirement because it must sell more capacity.
The load factor result can be changed in a number of different ways. For example, the load factor result can be altered by raising or lowering the demand forecast,80 using a different net firm capacity amount, making adjustments to the utilization of a particular path, or accounting for the extra revenue generated by the sale of as-available capacity. All four load factor proposals reflect these kinds of possible adjustments.
Before deciding which load factor method and number we should adopt, we need to address the primary and secondary recommendations of CAPP.
CAPP's primary proposal is that path-specific rates be adopted. CAPP contends that this will equalize gas competition because each path will have its own load factor, and it will eliminate the price difference which favors Southwest gas. Under CAPP's proposal, the costs of Lines 400 and 401 would be completely rolled-in, and the Redwood Path rate would be $0.221 per Dth. The Baja rate would be $0.282, and Silverado and Mission would be $0.113.81
CAPP's secondary proposal is for a single, average rate for all paths, often referred to as a postage stamp rate. This proposal also calls for the roll-in, or averaging of the costs of Lines 400 and 401.
Since we do not adopt the proposal of PG&E and the other parties to partially or fully roll-in the costs of Line 401 to the core, CAPP's proposal for path-specific rates, and for a postage stamp rate, are not adopted. We also note the concern of PG&E and TURN that path-specific rates are likely to raise costs by increasing the transportation rate on the Baja path, and that path-specific rates are likely to hinder competition rather than promoting competition.
We turn next to the load factor proposals of CCC/Calpine, TURN, and PG&E. CCC/Calpine's proposal is designed to account for the sale of all backbone services that PG&E is expected to sell in 2004, rather than a load factor based on expected system throughput. TURN's proposal is similar to the proposal of CCC/Calpine in that it is designed to adjust the throughput on Line 401 for the risk that PG&E took when it built Line 401. PG&E's load factor is the lowest of all the proposed load factors, and is based on its demand forecast with certain adjustments.
In order for us to decide on which load factor method and load factor amount should be adopted, it is useful to compare the proposed load factors with the actual load factors in prior years. As shown in Table 1 of Exhibit 30, the testimony of the CAPP witness, the load factors for 1998, 1999, 2000, 2001 and 2002 were 78%, 77%, 81%, 89% and 79%, respectively.82 PG&E's load factor of 68.4% is quite a bit below the historical load factors that were experienced during the Gas Accord. If we adopt PG&E's demand forecast without any adjustment, and its load factor method and percentage, the likelihood that PG&E will recover its revenue requirement is high in light of the historical load factors.
The difference in load factors is even more pronounced when the CCC/Calpine table showing the "load factor based on services sold" is used as a comparison. According to Table 8 of Exhibit 6 (page 2 of 2), the load factors based on services sold were 86%, 86%, 93%, 101% and 97% in 1998, 1999, 2000, 2001, and 2002, respectively.
PG&E contends that its load factor percentage should be adopted because its "lower load factor reflects the recent changes in gas and electric demand, primarily reflecting conservation efforts and a slower economy." (Ex. 3, p 14-15.) The parties who propose a higher load factor contend that PG&E has underestimated its demand forecasts of electric generator and off-system deliveries, which results in a lower load factor. In addition, they contend that PG&E's load factor fails to take into account revenues from the sale of as-available services.
Based on the load factors experienced during the Gas Accord period, and the need for just and reasonable rates while providing PG&E with the opportunity to recover its costs and a reasonable rate of return, we believe that a load factor higher than what PG&E proposes should be adopted.
As discussed in the demand forecast, we adopted the adjustment to off-system deliveries to reflect the likelihood that off-system deliveries will remain unchanged or increase. This adjustment to off-system deliveries, using PG&E's load factor method, works out to a load factor of 70.85%.83 This load factor is still below the load factors experienced previously. This comparison suggests that the demand forecast is too low, or that PG&E has underestimated its ability to market its backbone services. PG&E's load factor of 68.4% also suggests that there may be excess capacity, which could be sold to an entity such as SMUD.
To achieve a balance between just and reasonable rates, and to provide PG&E with the opportunity to recover its costs and a reasonable rate of return, an adjustment should be made to the load factor so that it correlates more closely to the load factors experienced during the Gas Accord period. Such an adjustment is warranted because PG&E's proposed load factor is inconsistent with past usage on PG&E's transmission system.
For this purpose, TURN's load factor method should be used. In reviewing D.90-12-119 (39 CPUC2d 69), D.94-02-042 (53 CPUC2d 215) and D.94-12-058 (58 CPUC2d 417), we agree with TURN that PG&E's shareholders were placed at risk for the Line 401 costs and revenues "as a condition of the `let the market decide' policy."84 (58 CPUC2d 420-421.) If PG&E's load factor of 68.4% is adopted for all of its transmission system, PG&E is no longer being held to account for the risk that it took on when Line 401 was authorized. That is, the risk associated with Line 401 gets diluted if PG&E's load factor method is adopted.
The utilization factor of 95% that TURN uses comes from D.94-02-042, the proceeding in which rates were authorized for Line 401. That load factor was adopted to calculate firm service rates, and to recognize that the risk of recovery of the costs of Line 401 was to reside with PG&E's shareholders. (53 CPUC2d at 226, 230, 237; 58 CPUC2d 423.) The Commission stated that "It is abundantly clear that any lower load factor will shield PG&E from the risks of unused capacity." (53 CPUC2d at 237.) In the Gas Accord, the parties agreed that the firm on-system backbone transmission charges should be based "on an annual average capacity factor of 87.5 percent." (73 CPUC2d 821.)
We note that the 95% load factor is very close the load factors experienced on the combined Redwood paths during the Gas Accord period. For 1998, 1999, 2000, 2001 and 2002, the combined Redwood Path load factors were 95%, 92%, 96%, 93% and 91%, respectively. (Ex. 30, Table 1, p. 11.)
Using TURN's method of adjustment, and the off-system delivery adjustment that we made in the demand forecast, the system load factor upon which backbone rates shall be based is 77.46%. This load factor is calculated as follows. In order to derive the load factor used to adjust the Line 401 throughput to reflect PG&E's risk, we added the additional off-system delivery of 79 MDth/d to PG&E's adjusted demand forecast of 2184.926 shown in Table 14-6 of Exhibit 3. The sum of those two numbers is 2263.926. Dividing 2263.926 by the total net firm capacity of 3195.292 results in a load factor of 70.9%. To account for the risk that PG&E undertook with respect to Line 401, the difference of .95 and .709 results in .241. The .241 is then multiplied with the net firm capacity of Line 401 of 875.463, resulting in an adjustment of 210.99. The 210.99 is then added to the adjusted demand forecast of 2263.926, resulting in the sum of 2474.916. The 2474.916 is then divided by the net firm capacity of 3195.292 to arrive at the system load factor of 77.46%.
For the purpose of designing backbone rates for 2004, the load factor of 77.46% is adopted. This load factor is at or below the load factors experienced on PG&E's transmission system during the Gas Accord period, and represents an equitable balance between just and reasonable rates, while providing PG&E with a reasonable opportunity to recover its revenue requirement.
PG&E shall continue to be at-risk for throughput and revenues on its backbone transmission system.
PG&E's total net firm capacity is based on the firm design capacities of each backbone path, as shown in Table 14-4 of Exhibit 3. That total is used to calculate the load factor, and to allocate the costs to the backbone paths. No one raised any objection to the use of these firm design capacities to allocate the costs to the backbone paths, or to use it as the denominator for calculating the load factor. We adopt those firm design capacities in Table 14.4 of Exhibit 3, and shall permit them to be used to allocate costs to the backbone paths, and for use in the denominator to calculate the adopted load factor of 77.46%.
PG&E proposes that the Redwood Path off-system rate be set to equal to the on-system rate. The reason for this change is because all of the Redwood Path capacity is being used to design on-system rates. No one objects to this proposal.
Under the Gas Accord, Redwood off-system rates are calculated using the incremental Line 401 costs and a 95% load factor. Since we have adopted the firm design capacities shown in Table 14-4 of Exhibit 3 to allocate costs to the backbone paths, we will adopt the proposal that the Redwood off-system rate equal the Redwood on-system rate.
PG&E proposes to assign vintage Redwood capacity to core retail and core wholesale as shown in Table 14-5 of Exhibit 3. We adopt PG&E's proposal.
PG&E makes reference at page 14-12 of Exhibit 3 that the "Non-vintage Redwood Path and Baja backbone capacity is assigned to meet each core customer's 1-in-10 year demand requirements." This passage is related to the core Winter Firm Capacity Requirement referenced at page 4-9 of Exhibit 3. Since we do not adopt the Winter Firm Capacity Requirement, the assignment of capacity on the non-vintage Redwood Path and Baja Path to meet the Winter Firm Capacity Requirement is not needed, and shall not be adopted. PG&E shall instead assign core capacity on the paths to meet the current guidelines, which is close to a 1-in-3 year cold temperature event.
PG&E proposes that the Schedule G-XF rates continue to be designed on an incremental basis in accordance with D.94-02-042 (53 CPUC2d 215.) We adopt PG&E's proposal.
PG&E makes reference at page 14-15 of Exhibit 3, and in its proposed tariffs, that the backbone rates are subject to the contingency rate adjustments that PG&E has proposed. However, as discussed in the contingency adjustment section of this decision, we do not adopt all of the adjustment mechanisms that PG&E is proposing.
Based on the proposals that we adopt, as discussed above, the backbone rates attached to this decision in Appendix A, Tables 3 to 9, shall be adopted as the backbone rates in this proceeding.
As mentioned in the Storage Services section of the decision, we have revised the assignment of capacities for Core Firm Storage, Standard Firm Storage, and Balancing. The revisions to the injection, inventory, and withdrawal capacities of those three service is due to the non-adoption of certain PG&E proposals, as previously discussed. Table 4 in the Storage Services section of this decision sets forth the assignments that we use for allocating the storage cost of service.
PG&E proposes to continue the storage rate design structure for Core Firm Storage. The core storage rate will continue as a single monthly capacity charge, and reflect the core's allocation of the storage costs. The core firm storage rate is shown in Table 10 of Appendix A.
For customers taking service under Schedule G-SFS, PG&E proposes to combine the capacity charge and the withdrawal charge into a single capacity charge. No one has objected to this proposed change. PG&E's proposal to combine the two charges is adopted.
PG&E proposes no changes to the negotiated firm or negotiated as-available storage services, or to parking and lending services.
The rates for G-SFS, negotiated firm, negotiated as-available, and parking and lending are shown in Table 10 of Appendix A.
The storage costs allocated to pipeline load balancing will continue to be bundled in all backbone transmission rates.
PG&E proposes to continue the self-balancing option. PG&E's design of the self-balancing credit is based on 80% of the total storage balancing assets. Those who elect self-balancing would receive a credit of $0.006 per dth, instead of the current $0.005. This is shown in Table 13 of Appendix A. We adopt PG&E's proposal to continue the self-balancing service option for 2004 and 2005.
CCC/Calpine propose the creation of a backbone-level rate structure, which is also referred to as a backbone-only rate. Under this proposal, customers that connect directly to PG&E's backbone pipeline system and, as a result, do not receive any local transmission service, will pay a backbone-only rate that does not include local transmission costs. CCC/Calpine contend that such a rate will end the current subsidy of local transmission customers by backbone-level customers, and ensure that backbone-level customers do not have to pay for services that they do not receive. CCC/Calpine also assert that the backbone-level rate proposal will better align PG&E's local transmission rates with the cost to serve local transmission customers, and fully complies with the applicable law.
CCC/Calpine assert that PG&E's proposal for a four-tier local transmission rate structure perpetuates the cross-subsidies that currently exist, and creates new ones. Under PG&E's proposal, the largest customers will still be obligated to pay a significant sum for local transmission service that they do not receive. They also assert that PG&E's proposal fails to comply with the requirements of §§ 453(a) and 454.4, which requires that cogenerator rates be set in parity with the rates of other electricity generators and prohibits undue preferences in the setting of rates.
CCC/Calpine recommend that the Commission reject PG&E's four-tier local transmission rate proposal for a number of reasons.
First, CCC/Calpine assert that PG&E's proposal is not based on a customers' actual cost-of-service. Although PG&E claims that its four-tier proposal is justified because a customer's cost-of-service decreases as a customer's size increases, PG&E has not demonstrated that customer size is an actual driver of PG&E's cost to provide local transmission service. CCC/Calpine assert that PG&E's proposal relies on an unproven and erroneous correlation between the customer's size and cost of service. For example, if size drives the cost of service, one would expect under PG&E's proposal, that the smaller Tier 2 customer should pay much more than the larger Tier 3 customers. However, under PG&E's proposal, the rates of Tier 2 and Tier 3 customers are virtually identical.
CCC/Calpine contend that under PG&E's proposal, small customers with high load factors or that are located close to the backbone end up paying a more expensive rate than under the Gas Accord. Large customers with lower load factors, or that are located far from the backbone, get a rate decrease, which is not merited in light of their heavier use of the local-transmission system. CCC/Calpine assert that the local transmission rates proposed by PG&E simply do not correlate with cost of service.
CCC/Calpine also point out that PG&E's only cost study regarding its local transmission proposal is based exclusively upon distance from the backbone and the cost to connect to the backbone, not size related cost differences. CCC/Calpine assert that PG&E's cost study is riddled with methodological inconsistencies, including the failure to demonstrate why customers located the same distance from the backbone with a similar cost of service should have dramatically different rates. CCC/Calpine also contend that the failure to include Duke's Morro Bay plant in the study biased the results in favor of unduly lowering rates for larger customers.
CCC/Calpine contend that PG&E's only cost study did not address economies of scale.
TURN stated that PG&E's four-tier proposal is completely arbitrary because PG&E uses the unorthodox mechanism of setting arbitrary rates for certain noncore customers before allocating costs among core and noncore.
CMTA agrees that PG&E has not demonstrated that size drives costs, and that PG&E's proposed local transmission rates are arbitrary. ORA and DGS are also opposed to the proposal. Due to the fact that so many parties agree that the PG&E's local transmission proposal is arbitrary, unjustified, and will not discourage bypass of PG&E's local transmission system, the Commission should reject the PG&E local transmission proposal.
CCC/Calpine's second reason for rejecting PG&E's proposal is that it continues existing subsidies, creates a new level of improper subsidies, and unfairly impacts competition in the electricity market. Customers who have built and paid for their own laterals to PG&E's backbone system for backbone-level service, would under PG&E's proposal, be required to pay a rate that includes a full local transmission component. Paying for a service that customers do not use, results in backbone-level customers having to subsidize the rates of other electricity generators who receive local transmission service from PG&E, such as Duke. This subsidy by backbone-level customers provides Duke, and other similarly situated customers, with an unearned competitive advantage of a subsidized rate and no capital investment in pipeline infrastructure. If PG&E is allowed to charge its electricity generators the PG&E local transmission rate of $0.075 to $0.157 per Dth, the cost of production will be inflated for merchant generators that are located close to PG&E's backbone system. As a result, these merchant generators will be less able to compete with a local transmission generator who enjoys a subsidized gas transportation rate. In addition, under PG&E's proposal, smaller electric generators with relatively high load factors, or that are located close to the backbone, will have to pay unduly high local transmission rates and subsidize the rates of larger customers with lower load factors, or who are located further from the backbone. This also has an unfair effect upon competition in the electricity market.
CCC/Calpine's third reason for rejecting PG&E's proposal is that it requires backbone-level customers to pay for local transmission that they do not use, and these customers will continue to seek a backbone-only rate or other mechanism that properly reflects their true cost-of-service. Under PG&E's proposal, backbone-only customers would be charged 7.5 cents in Tier 4, and 15 cents in Tier 3 for local transmission service these customers do not use. The proposed local transmission charges make up 61% and 75% of a Tier 4 and Tier 3 backbone-level electric generator's total rate. CCC/Calpine assert that the adoption of PG&E's local transmission proposal will do little to satisfy the legitimate desire of backbone-level customers to stop paying substantial sums for services that they do not use.
The fourth reason why CCC/Calpine believe that PG&E's proposal should be rejected is that the proposal violates § 454.4. That code section requires that the rates for gas, which is utilized in cogeneration technology projects, not be higher than the rates established for gas utilized as a fuel by an electric plant in the generation of electricity. PG&E contends that its proposal is similar to the electric generator-class proposal which was approved in SoCalGas' BCAP, and which complied with § 454.4. CCC/Calpine contend that the size-based rate design in SoCalGas BCAP was approved because it was functionally identical to a segmented rate design approach that was based on service level. CCC/Calpine contend that unless PG&E can demonstrate that the size-based tiers act as a proxy for level of service, PG&E's proposal would violate § 454.4.
Another reason why CCC/Calpine believe that PG&E's proposal should be rejected is that the rate design is based on arbitrary size classifications which is in violation of § 453(a). With the possible exception of customers within Tier 4, who use 125 million therms or more per year, PG&E has not offered an explanation as to why it proposes to segment tiers 1 through 3.
Due to the arbitrary size classifications, CCC/Calpine assert that PG&E's proposal would subject customers to undue discrimination in violation of § 453(a). Discrimination would result because customers who do not use local transmission service will be subsidizing customers who use local transmission service, and smaller customers with lower costs-of-service will be subsidizing larger customers with higher costs-of-service.
CCC/Calpine point out that PG&E has demonstrated the arbitrary nature of its own four-tier proposal by suggesting in its briefs, that it would be appropriate to collapse Tier 2 and Tier 3 into one tier, and change the 4 tier proposal into a 3 tier proposal. Such a suggestion implies that PG&E's size-based rate theory is erroneous because customers in tiers 2 and 3, despite their differences in size, would be assessed the same rate.
The fifth reason why PG&E's proposal should be rejected is that it is an inappropriate attempt to appease the proponents of a backbone-only rate with a moderate rate decrease, while imposing an arbitrary size-based tier system that will only foster more contentious Commission proceedings. The sole purpose of PG&E's proposal is to discourage certain customers from seeking implementation of a backbone-only rate. However, PG&E's proposal fails to align rates with cost-of-service because backbone-level customers would still be charged for local transmission services.
TURN also stated that it is not good policy for PG&E to try to appease certain customers with the promise of a discount. TURN warns that such a strategy will only cause the large noncore customers, who threaten to bypass, to push again for a backbone only rate at the next available opportunity.
CCC/Calpine contend that the few parties who support PG&E's four-tier proposal seek to continue the subsidy that they are receiving or seek a second best alternative to backbone-level service. NCGC supports the four-tier proposal because the backbone-only proposal would unfairly penalize customers who might have located their facilities closer to the backbone if a backbone rate had existed. CCC/Calpine assert that facility siting decisions are more complex than just considering whether a backbone level rate is available. CCC/Calpine also assert that its backbone-level proposal penalizes no one, and remedies an improper cross-subsidy that currently exists in rates.
Duke argues that the four-tier proposal equalizes competition among generators located in PG&E's service area. CCC/Calpine assert that Duke's argument cannot be given weight because a rate design that divides customers into four tiers, and charges different rates based upon the customers' size, will not equalize competition. CCC/Calpine argue that PG&E's four-tier proposal unfairly benefits large, low load factor customers, such as Duke, who are located far from the backbone, at the expense of both smaller and backbone-level customers.
CCC/Calpine propose the adoption of a backbone-level rate structure in which customers connected to PG&E's backbone pay a backbone-only rate, and do not have to pay for any of the costs associated with local transmission. CCC/Calpine also propose that the single average rate for noncore local transmission service be retained.
CCC/Calpine assert that its backbone-level proposal aligns customers' rates with their cost of service by adhering to the principle that customers should not pay for services that they do not receive, and "to achieve rates which reflect the costs that the customers imposes on the system." (D.96-04-050 at 3.)
CCC/Calpine contend that the backbone-level rate structure is needed to avoid bypass of PG&E's backbone service. This bypass situation has arisen because customers can connect directly to interstate pipelines within PG&E's service territory without having to pay PG&E's local transmission charges.
CCC/Calpine contend that the Commission has taken several actions similar to its backbone-level proposal. These actions include differentiating the costs of the backbone, distribution, and transmission functions, and establishing different rates for distribution and transmission-level customers in all three utilities' service territories. CCC/Calpine also assert that the Commission endorsed in principle a backbone-only rate for PG&E, but that rate was never implemented in light of the settlements reached in the Gas Accord. CCC/Calpine contend that the next logical step for improving cost causation is to implement a backbone-only rate design for noncore local transmission service on PG&E's system.
CCC/Calpine point out that in D.92-12-058 (47 CPUC2d at 448), the Commission established different rates for distribution and transmission-level customers. Large transmission-level customers do not have to bear the costs of distribution system that serves much smaller distribution-level users. CCC/Calpine contend that the Commission's reasoning in D.92-12-058 should be extended to backbone-level customers and the local-transmission system.
CCC/Calpine point out that the Commission already allocates costs separately for backbone and local transmission services. PG&E customers also are allowed to purchase backbone level service. The Commission should unbundle the local transmission charges from backbone service.
CCC/Calpine contend that PG&E's single electric generation class proposal in this proceeding is another example of cost allocation and rate design based on level of service. PG&E's single electric generation class proposal distinguishes between transmission and distribution-level electric generators, which is the same as the backbone-level rate structure proposal.
CCC/Calpine assert that its backbone-level proposal is supported by Commission precedent. In D.95-12-053, the Commission considered a request from SMUD that is virtually identical to the backbone-level proposal in this proceeding. SMUD built its own pipeline to connect to Lines 400 and 401. In PG&E's 1994 BCAP, SMUD asked the Commission to implement an unbundled rate for backbone level noncore industrial and cogeneration customers. In D.95-12-053, the Commission stated that "an unbundled backbone-only rate is consistent with our general direction for the gas industry." The Commission then initiated a second phase of the proceeding to consider more fully SMUD's proposal to create a backbone transmission rate. (63 CPUC2d at 451, 461.) The second phase never materialized as SMUD's desire for a backbone level rate was resolved as part of the Gas Accord. (73 CPUC2d at 838.)
In the Gas Accord, SMUD received a discount of about 94% of the PG&E local transmission charge ($0.0123 per Dth out of $0.131 per Dth.) CCC/Calpine contend that the Gas Accord essentially recognized the legitimacy of a backbone-only rate for customers like SMUD, who received a highly discounted rate.
CCC/Calpine also assert that the backbone-level proposal is supported by Resolution G-3338 (Feb. 27, 2003). In that situation, a gas distribution-level customer, Praxair, asked SoCalGas for permission to tap into the local transmission system because it would result in a lower rate and cost savings to the customer. In the resolution, the Commission decided that if Praxair wanted transmission-level service, it would be allowed to do so and should be reclassified accordingly. The Commission also expressed concern about the impact of the switch, and whether it would impose stranded costs on the remaining distribution-level customers. SoCalGas was ordered to file an advice letter for similar requests, along with an estimate of the amount of stranded costs associated with each customer's request. The resolution stated that such customers "will be expected to pay for the actual stranded costs that result from such transfers." (Resolution G-3338 at 7, 12.)
CCC/Calpine contend that it may be appropriate, depending on the circumstances, for customers who leave the local transmission system to connect to the backbone, to pay for the stranded local transmission costs they might create. However, under the Praxair reasoning, customers who never used local transmission facilities, but merely opted at the beginning to build their own connection to the backbone system, should not have to pay for any stranded costs because they were not responsible for the incurrence of such costs. TURN's witness acknowledged that this should be the result in that kind of situation.
Duke and PG&E argue that a backbone-level proposal will unfairly affect competition in the electricity markets. CCC/Calpine contend that because its proposal is grounded firmly on cost of service principles, and because it eliminates cross subsidies, the backbone level proposal is not unfair at all.
CCC/Calpine point out that Duke prefers PG&E's four tier proposal out of its own self-interest. PG&E's proposal would continue the subsidization of Duke by Calpine and other backbone-level customers, and create new subsidies of Duke by smaller electricity generators and cogenerators.
CCC/Calpine contend that its backbone-level proposal complies with the requirement in § 454.4 that electric generators and cogenerators have rate parity. CCC/Calpine assert that the backbone-level proposal, which segments rates by service level, complies with § 454.4.
In response to concerns that the backbone-only rate might result in cogenerators seeking an equivalent rate, CCC/Calpine state its proposal would not entitle cogenerators connected at the local transmission-level to claim a backbone level rate under § 454.4 because the proposal validly distinguishes between rates for different levels of service. The Commission has construed § 454.4 to allow for parity based on the specific service being provided. For example, under the Gas Accord cogenerators taking firm service receive parity with other electricity generators taking firm service, while cogenerators taking interruptible service receive parity with other electric generators taking interruptible service. (See 73 CPUC2d at 823-824.) Similar action was taken in D.00-04-060, where SoCalGas and SDG&E were allowed to charge rates for cogenerators and other electricity generators connected at the distribution-level that differ from the rates charged to those that connect at the transmission-level. CCC/Calpine assert that PG&E's concern regarding parity under § 454.4 is a red herring and should be rejected.
CCC/Calpine also assert that the backbone-level rate proposal complies with § 453(a) because it is not based on arbitrary distinctions among customers. Instead, its proposal is based on the services that customers receive and which reflect their cost of service.
CCC/Calpine contend that another advantage of the backbone-level proposal is that it will improve reliability for local transmission customers in at least two ways. First, the implementation of a backbone-only rate is likely to result in at least some customers shifting from local transmission service to backbone-level service. Also, new customers that have the option to connect to either local transmission service or backbone-level service, will likely choose backbone-level service. CCC/Calpine contend that this will result in more capacity being available on the local transmission system. This extra capacity can then be used to serve load growth in that area.
CCC/Calpine contend that the backbone-level proposal also strengthens reliability because customers constructing and maintaining their own laterals will enable PG&E to defer having to expand or reinforce its local transmission system, thus avoiding significant reinforcement related expenses.
Duke contends that under a backbone-level rate structure, two power plants or two manufacturing facilities, with similar load characteristics, load volumes and service pressures, would pay vastly different rates if one were connected to the backbone, and the other was not. CCC/Calpine point out that customers, such as Duke, will pay higher rates because they are more expensive to serve than customers connected to the backbone. The backbone-only rate will also remedy the competitive inequity that a customer such as Calpine faces, i.e., having to pay for local transmission service that it does not use.
Duke argues that a backbone-only rate will unfairly tilt the competitive playing to favor generation projects which are located near the pipelines that are currently designated as backbone, regardless of any plant efficiencies or prudent commodity fuel cost purchases. Other noncore gas customers would experience the same competitive imbalance. CCC/Calpine contend that the issue is whether two customers who are physically connected to different levels of service, should have to pay the same rate.
Duke questions whether a backbone-only rate will lead to the appropriate siting of new power plants. CCC/Calpine contend that the backbone-only rate allows customers to better tailor plant sites to their needs by providing a rate that tracks the true cost of siting near the backbone system. Also, CCC/Calpine assert that the appropriateness of a backbone-only rate, and the creating incentives to site power plants near load centers are two separate and distinct issues.
One of PG&E's arguments against the backbone-level rate proposal is its doomsday scenario in which 600 MDth/d of load departs the local transmission system for backbone-level service, resulting in a massive shift of costs onto those remaining local transmission customers. CCC/Calpine assert that PG&E's estimate is unlikely to occur because of the location of these customers, and the need to built laterals to connect them to the backbone. At most, 199 MDth/d of load might migrate to backbone-level service.
Even if the Commission were to pay attention to PG&E's forecast of migration, CCC/Calpine assert that PG&E overlooks the mechanisms that could mitigate these impacts, such as an exit fee similar to what was discussed in the Praxair resolution, or PG&E can selectively discount local transmission rates.
CCC/Calpine contend that a decision on the backbone-only rate is long overdue, and should not be deferred again.
Coalinga is the second largest wholesale customer on PG&E's system. Coalinga owns and operates a municipal gas distribution utility and provides natural gas service to residential and small business customers within its boundaries. Coalinga's annual gas requirement is about 2.2 million therms per year (220 MDth), 100% of which is classified as core. As a wholesale customer, Coalinga is both a purchaser and reseller of natural gas. The cost of transporting gas over PG&E's gas transmission system is an important component of Coalinga's cost of service.
Coalinga points out that under the Gas Accord settlement, Coalinga and PG&E's other wholesale customers have paid the same average local transmission rate as all other noncore customers. This rate is presently $0.149 per Dth and reflects an escalated revenue requirement of $153.9 million. This rate is consistent with the Commission's policy that wholesale customers are noncore customers with core load responsibilities. Although Coalinga was not a signatory to the Gas Accord settlement, Coalinga views the settlement as consistent with this policy, and such a policy should be retained beyond 2003. PG&E's proposal to change the wholesale rate would require Coalinga to pay the same local transmission rate as retail core customers is a radical departure from this policy.
Under PG&E's proposal, the revenues allocated to retail core and wholesale core loads would be combined and divided by the sum of their combined throughput to establish a single local transmission rate of $0.419 per Dth. PG&E proposes to charge this rate to both retail core customers and the core loads of its wholesale customers. As a result, Coalinga's local transmission rate would increase by over 180%. Coalinga agrees with Palo Alto, that this disproportionate increase is contrary to the Commission's well-established practice that regulators should pursue stability and consistency in setting rates and avoid rate shock. PG&E's witness concedes that under PG&E's proposed methodology, the rate impacts on core and noncore customers are more dramatic than if the Gas Accord methodology were used to compute local transmission rates.
Coalinga opposes PG&E's proposal, and supports the position taken by Palo Alto. Coalinga points out that the issue of charging wholesale customers the same rates as retail core customers was not identified in the February 26, 2002 scoping memo as an issue, nor was it included as an issue in any subsequent ruling. In addition, PG&E's proposal would violate the Commission's policy that wholesale customers are members of the noncore class with core load responsibilities. Coalinga contends that PG&E's proposal to charge wholesale core loads at a retail core rate violates this policy. Also, the proposed increase in the wholesale rate exceeds what is reasonable, and what is being proposed for other customer classes.
Coalinga points out that wholesale customers on SoCalGas' system do not pay core rates. Coalinga requests the Commission to take official notice of SoCalGas' 2000 BCAP decision, D.00-04-060. In that decision, the rates of SoCalGas' wholesale customers, SDG&E and the City of Long Beach, were set forth in the noncore transportation rates, and were not included as part of the total core revenue requirement.
If the Commission determines that it is necessary to update the local transmission revenue requirement or to modify the rate structure for 2004, it should direct PG&E to use the Gas Accord methodology and charge wholesale customers the local transmission rate that is applicable to other members of the noncore class.
The primary purpose of the participation of Duke Energy North America and Duke Energy Trading and Marketing, collectively "Duke," in this proceeding was to contest the proposal of CCC/Calpine and Mirant for a backbone-level gas transportation rate. Duke supports PG&E's proposal for a four-tier local transmission rate for noncore customers and for an improved reliability standard for noncore customers.
CCC/Calpine propose that the Commission approve a new, backbone-level transportation rate that would be available to customers who are able to connect directly to the pipelines that make up PG&E's backbone system. Under the proposal, a select group of customers would no longer be required to pay for any portion of PG&E's local transmission system.
Duke contends that the backbone-only rate is anticompetitive and favors Calpine, Mirant, and some of CCC's members. Under the proposal, the transportation costs for these customers would be reduced by 14.9 cents/Dth, while their direct competitors' costs would be increased by 2.4 cents/Dth to 17.3 cents/Dth. If a lower system load factor than the one CCC/Calpine propose is adopted, the 17.3 cents/Dth advantage would grow even larger. This differential provides CCC/Calpine with a competitive advantage because it lowers their cost of electric generation, which will have an effect on competition in the electricity market. The Commission recognized this when Calpine presented its backbone-only proposal before. The Commission stated: "The relief requested [the backbone-only rate] would provide more favorable treatment to specific merchant power plants that would obtain a distinct competitive advantage over other merchant generators in California by avoiding payment of local transmission charges which all other on-system merchant generators pay." (D.01-05-086 at 18.)
Duke is impacted by the CCC/Calpine proposal because Duke's gas-fired plants in PG&E's service territory are located on the coast, far away from PG&E's backbone system. If the backbone-only rate is adopted, Duke would have no cost-effective way of constructing a pipeline to connect directly to PG&E's backbone system. Based on Duke's estimated 2002 gas usage at its Moss Landing and Morro Bay power plants, Duke would pay $13 million per year in local transmission rates if the backbone-only rate is adopted, while Calpine and others would pay nothing for local transmission.
Duke asserts that the proponents of the backbone-only proposal gain in two ways. First, the proponents would receive lower rates under the proposal, and second, the proposal would raise the costs of their direct competitors.
CCC/Calpine suggest that the backbone-only rate is not unfair. Duke and others note that apart from the obvious economic effects of the proposal, this sudden shift in the regulatory ground rules has the effect of punishing those companies who, like Duke, have invested hundreds of millions of dollars to improve the energy infrastructure in California. Also, the Commission has acted to eliminate rate structures that require some California generators to pay much higher rates for gas transmission than others, solely due to their location. (See D.00-04-060.) The Commission stated in D.00-04-060 that competition among electric generators should be based on the efficiency of generating units and the shrewdness of their owners in the gas procurement and financial markets, not on the happenstance of where their plants are located. (D.00-04-060, p. 142.)
CCC/Calpine contend that the backbone-level proposal furthers the principle that customers should not pay for services that they do not receive. Duke asserts that this is an oversimplification. Instead of focusing in on the needs of CCC/Calpine only, the Commission must balance the interests of the diverse group of entities that form the general body of ratepayers to arrive at a result that is in the overall public interest. When faced with this constraint, the backbone-only rate proposal falls well short of the goal of furthering the overall public interest.
Duke points out that customers in one part of PG&E's system do not make use of other, distant portions of the system. However, due to the Commission's policy of maintaining uniform, geographically averaged rates for the same customer class and schedule throughout PG&E's system, many (if not most) customers pay for parts of the system they do not use.
As for CCC/Calpine's assertion that rates should be based on cost of service, Duke says that cost of service is just one of the factors that Commission typically considers when it sets rates. Dukes asserts that the Commission's primary goal is to further the actions and policies that it determines are in the public interest. If one pursued cost-based rates to the extreme, this would require individualized rates for each customer, a practical impossibility. Also, the pursuit of cost-based rates would conflict with the broader and more important goal of pursuing the public interest.
Duke asserts that the Commission tries to operate in the middle of two extremes, a separate tariff schedule for all customers, or a single tariff schedule for all customers. That is, the Commission groups similarly situated customers into customer classes and then develops a handful of tariff schedules for the customers within a class. Rates are generally set to correspond to the costs of customers falling within a particular schedule, but the Commission is neither a slave to cost-based rates nor is it troubled when some customers are required to pay for services that they do not use. Thus, there are so-called "cross-subsidies" inherent in the Commission's ratemaking policies, such as urban subsidizing rural, long-time customers subsidizing new arrivals, and customers served by fully depreciated facilities subsidizing those who are served by newly constructed facilities. The Commission, however, has determined that rate averaging of this sort is in the public interest.
Duke contends that the Commission has previously determined that competitors should not be advantaged or disadvantaged solely because of the location of their facilities. In D.00-04-060, the Commission created competitive rate parity among electric generators in the service territories of SoCalGas and SDG&E by resolving the mismatch between uniform statewide electric prices and utility-specific gas transportation rates. (D.00-04-060, FOF 32 and 33.) A backbone-only rate would recreate the problem that D.00-04-060 corrected. In D.01-05-086, the Commission recognized the competitive problems with a backbone-only rate that Calpine sought in that proceeding.
Duke accepts that the newer combined cycle generation plants will typically be more efficient than its older Moss Landing and Morro Bay power plants, and that this higher efficiency will give these newer plants a competitive edge. However, the backbone-level rate proposal would manufacture a competitive advantage by regulatory action. Duke contends that the Commission should be consistent with the principles stated in D.00-04-060 and encourage competition based on efficiency and investments to improve efficiency. A rate structure that discourages investments in efficiency and rewards some competitors based solely on their location should not be adopted.
Another reason why Duke recommends that the proposal be rejected is that core customers and the remaining noncore customers will face increased costs and higher rates. Under the backbone-level proposal, the core's local transmission rate will increase from the current rate of 28.7 cents/Dth to 38.1 cents/Dth. The noncore local transmission rate would increase by at least 2.4 cents/Dth. Duke asserts that more costs will shift to core customers in later years because electric generators who cannot connect to the backbone will generate less electricity as a result of the competitive disadvantage. As these noncore customers make less of a contribution to the recovery of the costs of the local transmission system, local transmission rates will increase during the next revenue allocation process, and the cycle will repeat itself resulting in a "death spiral." In addition, the noncore customers who can connect to PG&E's backbone, are likely to do so to avoid local transmission charges. This will result in the shifting of local transmission costs to the remaining core and noncore customers.
Duke also warns that if the backbone-level proposal is adopted, that noncore customers may decide to relocate to sites adjacent to PG&E's backbone system, or may seek interstate pipeline service. In either event, this will lead to less customers paying local transmission charges, and the death spiral would continue.
Duke contends that the Commission has not clearly articulated a policy in favor of an unbundled backbone-only rate. Although CCC/Calpine cite D.95-12-053 as supporting such a rate, Duke asserts that the decision also raised several concerns about a backbone-only rate, including concern about "the magnitude of the cost shifting that may result from a separately tariffed backbone rate. (D.95-12-053 [63 CPUC2d 414, 451].) Duke also points out that the Commission has yet to approve a backbone-only rate. With conditions in the energy industry still unsettled, Duke contends that this is not the time for the Commission to rearrange significant components of the gas delivery system.
Duke asserts that for the natural gas and electricity industries, the Commission has long maintained a policy that rates should be geographically averaged and uniform for similar customers grouped into customer classes. As stated by the Commission in D.99-11-023, "Rates are set on a uniform basis, by customer class, using average cost throughout the service area. (D.99-11-023 at 24.) The Commission also stated that a uniform, geographically average rate "spreads the cost of differential investments in city and rural areas, creates a larger number of customers to share the costs of repairs from disasters and for disaster prevention," and helps spread the costs of public purpose programs. (D.99-11-023, p. 25.)
If the backbone-level rate proposal is adopted, this would create a two-zone system for recovery of the costs of the local transmission system. Those noncore customers who are located close to PG&E's backbone system would not contribute to the costs of the local transmission system, while customers located farther away, who are otherwise identical, would bear the local transmission costs.
Duke points out that if the purpose behind the backbone-only rate is to eliminate the subsidies inherent in average rates, the proposal should have been based on a mileage-based rate for the backbone system. Instead, the CCC/Calpine proposal is split into two categories, those located adjacent to the backbone system, and those who are located away from the backbone system.
In the expansion proceeding addressing Line 401, the Commission approved a "postage stamp" rate, i.e., a single rate for all shipments using the expansion, regardless of delivery point. (39 CPUC2d 69, 163, FOF 17.) Some parties challenged the rate because, they argued, it was subsidized by Northern California shippers whose gas does not traverse the length of the expansion. Such an argument is similar to the argument of CCC/Calpine. The Commission rejected the argument, and stated that it wanted to encourage efficiencies of scale and scope, and to promote the economic development of the state as a whole. (40 CPUC2d 497, 504.) Duke asserts that by allocating backbone and local transmission costs to all customers helps to encourage efficiencies of scale and scope, and it promotes the economic development of all of PG&E's service territory, instead of just along the backbone system. The Commission should therefore direct in this proceeding that all noncore customers pay rates that reflect the costs of the local transmission system.
Duke contends that another consequence of the backbone-only rate is that duplication of facilities is likely. The customers who connect directly to the backbone with a lateral pipeline have no obligation to serve new load growth adjacent to the lateral or their plant. When load growth occurs near the lateral, PG&E may have to construct a new facility, parallel to the privately owned lateral, to serve that new load because of PG&E's obligation to serve. Duke asserts that this is not an efficient outcome.
Another argument that CCC/Calpine raised is that its proposal is consistent with the Commission's policies on unbundling. Although the Commission has established separate backbone and local transmission rate components, the Commission has never approved any of several proposals for a backbone only rate that have come before the Commission previously.
CCC/Calpine contend that the backbone-only rate will help PG&E attract and retain major gas loads and will help reduce backbone rates for all customers. Duke contends that no benefits for other customers will result from the backbone-only rate unless the decrease in backbone rates for other customers is enough to offset the rate increase that these customers will face when the backbone-only customers shift their costs of the local transmission system onto them. The proponents of the backbone-only rate acknowledge that the proposal will increase local transmission rates for other customers by $5 million to $10 million in 2004. The local transmission rates for core customers would increase by 4.4 cents/Dth.
CCC/Calpine contend that a backbone-only rate will encourage the siting of generation in Northern California. Duke asserts that a backbone-only rate will discourage the siting of any new Northern California electric generation except along PG&E's backbone system. In addition, the anticompetitive effects of the backbone-only rate will make it more difficult for existing generators that are not able to connect directly to the backbone system to compete successfully for new power contracts or in the short-term power markets. If the electric generators located further from the backbone are unable to compete successfully in the power markets, existing generators will be less likely to invest in upgrading their plants.
Although the backbone-only rate may encourage the siting of new power plants along the backbone, electric ratepayers are likely to end up financing upgrades to the electric transmission system in order to deliver this power to customers. Duke contends that the backbone-only rate does nothing to ensure that a new generation plant will be located close to either load centers or existing transmission facilities. As the Commission noted in D.01-05-086: "[I]t is not clear whether providing a lower gas rate for power plants located along the backbone pipeline, at a distance from PG&E's electric load centers, would provide appropriate incentives for siting power plants at other locations better suited to help maintain the reliability of the electric transmission grid."
CCC/Calpine also cite the Praxair resolution in support of its backbone-only rate. Duke points out that in Praxair, the Commission merely applied existing tariff provisions, whereas CCC/Calpine seek to overturn existing practices and to radically alter the existing tariffs. Duke asserts that the stranded costs in the resolution were minimal, whereas the stranded costs that would result from a backbone only rate would be very significant. Thus, the Praxair resolution sheds no light on this issue, and the resolution stated it was not to be precedent setting. Duke points out that Praxair was a distribution customer, seeking transmission-level service, not backbone service.
Another argument of CCC/Calpine is that the backbone-only rate is consistent with rate design in the electric utility industry because electric utilities offer lower rates for customers who connect at higher voltages. Duke asserts that unlike the transformation losses in the voltage-based rate example, the local transmission costs in the backbone-only rate situation, do not disappear. Instead, these costs are shifted to the remaining customers on the local transmission system. The voltage based rate structure also has none of the anticompetitive elements of the backbone only rate, and is not a location-based rate. Duke contends that the voltage based rate example is a poor analogy to the backbone only rate.
CCC/Calpine assert that the backbone-only rate complies with § 454.4, citing the discussion of the segmented electric generation rate adopted in D.00-04-060. In that decision, the Commission stated that the adopted segmented rate proposal in the BCAP complied with § 454.4 because it treats all electric generators alike, regardless of their size, location, or present or former ownership. Duke says the same cannot be said of the backbone-only proposal, which favors a select group of generators over others, based solely on their locations in relation to the backbone.
Duke also warns that due to the parity provisions in § 454.4, if other cogenerators who are not directly connected to the backbone use that section to claim backbone-only rate parity, so as to avoid local transmission charges, the harm from the backbone-only proposal to other customers would even be greater than anticipated.
CCC/Calpine argue that the backbone-only rate is not arbitrary and complies with § 453(a). Duke points out that § 453(a) concerns rate preferences or discrimination with regard to any corporation or person. CCC/Calpine ignore the more relevant requirements of § 453(c) which forbids unreasonable rate differences "between localities." Duke asserts that the Commission's preference for geographically averaged rates is based, in part, on the requirements of section 453(c). The CCC/Calpine witness recognized that the distance between PG&E's backbone system and Duke's coastal generating plants effectively disqualified Duke from the backbone-only rate, and other noncore customers face the same kind of geographical discrimination. Duke asserts that the backbone-only rate essentially creates a two-zone noncore transmission rate, with customers located within the zone near the backbone system and connecting to the backbone paying a considerably lower rate for transmission than more distant customers.
CCC/Calpine also assert that the backbone-only proposal will help discourage bypass of PG&E's system. Duke states that it is probably true that the select group of existing customers who can connect directly to the backbone will be less likely to leave the PG&E system if CCC/Calpine's proposal is adopted. Duke contends, however, that the anticompetitive aspects of the proposal will encourage relocation resulting in more bypass, or it will put companies out of business. The proposal will also reduce the revenues these customers contribute to the costs of the PG&E backbone and local transmission systems, triggering the death spiral for remaining customers mentioned earlier.
CCC/Calpine contend that the backbone-only proposal will reduce the costs of PG&E's local transmission system. Duke asserts that this argument only considers one side of the accounting ledger. This argument is based on the assertion that as customers abandon the local transmission system for backbone-only service, they make more capacity available on the local transmission system to serve new growth, with the additional benefit that system upgrades can be deferred until needed. Duke asserts that this argument ignores the effects on those customers who remain and who must now bear the local transmission costs. Thus, any alleged benefits of the backbone-only rate must be weighed against the lost revenues from the departure of the backbone-only customers.
Duke also notes that making more capacity available on PG&E's local transmission system is just a code word for describing stranded costs. Making more capacity available when it is not needed to serve load (the circumstance that will by definition occur when an existing customer connects to the backbone to take advantage of the favorable rate) means that the remaining system will be underused. Yet the full costs still remain, which will have to be borne by the fewer remaining customers who are not in a position to connect to the backbone.
Duke points out that TURN opposes the backbone-only rate, but if it is adopted, TURN suggests that the rate be limited to new or incremental load. Duke points out that even if this was done, there would still be the imposition of costs on remaining core and noncore customers because the utility would be forced to build redundant facilities. Duke also points out that TURN's proposed limitation overlooks the principle that the Commission adopted for pricing of the PG&E Expansion, that the backbone system would not have been built in anything like its current dimensions without the participation of all customers, and that sometimes greater system benefits require the participation of all customers.
CCC/Calpine assert that the Commission has previously indicated support for the backbone-only rate. Duke points out that they gloss over the fact that the Commission failed to adopt the backbone-only rate three times in recent years, i.e., in D.95-12-053, D.99-11-023, and D.01-05-086. Even in D.95-12-053, in which CCC/Calpine rely on to support their position, the Commission stated that "There are a number of questions that need to be addressed before adopting a separate backbone-level rates..." including the magnitude of the cost shifting that may result from a separately tariffed backbone rate. (63 CPUC2d at 451.) Duke suggests that this decision is hardly the ringing endorsement of the backbone-only rate that CCC/Calpine would lead one to believe.
CCC/Calpine also assert that their proposal encourages the economic efficient siting of power plants. Duke contends that such a proposal will only encourage the siting of new electric generation plants near the backbone, without regard for how the plants relate to electric load centers or the electric transmission system. CCC/Calpine acknowledge this by stating the Commission could pursue "a separate mechanism to provide incentives for locating near electricity-load centers." Duke questions why the Commission should adopt one proposal that creates inefficient siting incentives, only to adopt another undefined incentive to counter the effects of the first proposal.
Duke contends that PG&E's four-tier proposal promotes competitive parity among similarly situated generators while maintaining the current requirement that all noncore customers must contribute to the costs of both the backbone and local transmission systems. Duke asserts that PG&E's proposal has several advantages. First, PG&E's proposal equalizes competition among generators located in PG&E's service area because it does not distinguish on the basis of where the plant is located. Second, PG&E's proposal attempts to respond to the competitive challenge that the interstate pipelines present to PG&E by way of bypass by developing a cost-based rate that reflects the lower costs of serving high-volume customers. Third, PG&E's proposal avoids draining the Commission's resources on considering and rejecting the backbone-only rate. And fourth, PG&E's proposal maintains the contribution of large noncore customers to the costs of the local transmission system.
Duke finds it ironic that the proponents of the backbone-only rate would benefit from PG&E's four-tier proposal, but oppose it because the backbone-only rate would provide them with even greater economic and competitive advantages.
Duke notes that Mirant, one of the proponents of the backbone-only rate, finds that the four-tier rate structure is the second best option. Mirant notes that the four-tier rate deters uneconomic bypass. Mirant also appears to agree that the four-tiered rate improves the cost basis for local transmission charges and reduces the potential for stranded costs.
Although LGS does not take a position on the issue of the backbone-only transmission rate, LGS is responding to some comments made by Duke regarding the issue of project location.
Duke cited D.00-04-060 for the proposition that competitors should not be advantaged or disadvantaged solely because of the location of their facilities. LGS contends that the decision does not stand for such a broad proposition. Although LGS leaves it to the parties to debate the applicability of D.00-04-060 to the backbone-only rate proposal, LGS is concerned that there should be no regulatory proposition in this proceeding which holds that location doesn't matter. LGS asserts that location frequently does matter, and to ignore the importance of location is counter to the normal facts of business life.
LGS is located close to the load center. LGS made substantial financial investments to gain approval of its project, and built it in reliance upon the benefits it believe its location would yield. Any statement which diminishes the importance of location in this proceeding could negatively impact LGS in the future. There are also ongoing disputes among various storage providers where such a statement could have an impact. LGS urges the Commission not to make any such broad pronouncements in its decision in this proceeding. If location is of importance to the backbone-only issue, LGS requests that the decision clearly state that the decision applies only to the circumstances presented here, and to no other.
Mirant recommends that the Commission adopt the proposal for a backbone-level rate structure that reflects the appropriate assignment of local transmission costs to customers who use local transmission facilities. Such rates would exclude backbone-level customers from the charges for PG&E's local transmission and distribution facilities, which they do not use. Mirant asserts that backbone-level rates are justified as the next logical step in the Commission's unbundling of gas transmission services and cost of service principles. Since this issue has been thoroughly examined, the Commission should act on the proposal.
Mirant points out that the issue of backbone-level rates is not new. It was raised in PG&E's 1994 BCAP proceeding in A.94-11-015 in connection with SMUD's development of several new gas-fired cogeneration projects. SMUD proposed a separate, unbundled rate for noncore industrial and cogeneration customers taking service directly from the backbone system. In D.95-12-053 the Commission stated that "an unbundled backbone-level rate is consistent with our general direction for the gas industry." The Commission deferred the backbone-level rate issue, and encouraged parties to address it in the Gas Accord negotiations that were underway. (D.95-12-053 at 61-63.)
SMUD's proposal for a backbone-level rate was addressed in the Gas Accord when SMUD was given a 94% discount on PG&E's local transmission charges, pending SMUD's purchase of an undivided interest in PG&E's Lines 300 and 401.
PG&E now delivers substantial volumes of gas to customers that are directly connected to its backbone system or that could easily make such connections. Mirant contends that PG&E's current uniform local transmission rate, which is in theory nonbypassable, actually encourages larger transmission-level customers to find bypass alternatives.
Mirant contends that backbone-level rates are consistent with cost causation and cost-of-service ratemaking. As Beach testified, "Customers that take service directly from the backbone system do not use, and should not pay for, PG&E's local transmission or distribution systems." Beach further states that an unbundled backbone-level rate structure will send correct price signals to all customers. (Ex. 6, pp. 16-17.)
Beach also mentioned several other benefits of an unbundled backbone-only rate. First, PG&E is relieved from having to make costly additions to its local transmission system to serve new load that can more efficiently be served by the customer's interconnection to PG&E's backbone system. Second, PG&E will be able to retain major gas loads that might otherwise relocate or seek interstate pipeline service. Third, the backbone-level rate sends correct price signals to customers, especially electric generation customers, that are able to interconnect directly to PG&E's backbone system. Fourth, the backbone-level rate will provide more reliable and less costly electric service once the artificial barrier of mandatory local transmission charges to backbone-level electric generation customers is removed. And fifth, a backbone-only rate will provide consistency with traditional voltage-based rate differentials in charges for electric service.
Beach recommends that the backbone-level rate structure be designed to include the following three unbundled components: (1) a path-specific backbone rate; (2) a customer access charge; and (3) a customer class charge. These rates would apply to all noncore loads that take service directly from PG&E's backbone system using either existing or new laterals paid for by the customer. The primary change in the rate design is that backbone-level customers would no longer be charged for the costs of local transmission service that they do not use.
Beach asserts that the impact of the backbone-level rate proposal for core and noncore local transmission service customers will be slight, and reasonable, given the inequity of the current requirement that backbone-level customers pay for local transmission service that they do not even use. Customers who do not need or use local transmission service should not be required to pay local transmission rates.
As part of the backbone-level rate structure, PG&E's four-tier local transmission rate proposal should be rejected. Beach proposes that the local transmission rate design from the Gas Accord be retained, i.e., distinct core and noncore local transmission rates, but applicable only to customers that actually take local transmission service. To the extent the backbone-only rate might encourage uneconomic bypass of PG&E's local transmission plant, the proposal would allow PG&E to offer selective discounting of local transmission rates. The proposal would also authorize balancing account protection for 75% of PG&E's local transmission revenue requirement for 2004. (Ex. 6, pp. 3, 26.)
Mirant contends that the backbone-level rate proposal is superior to PG&E's tiered local transmission rate proposal because it relieves backbone-level customers from having to pay for local transmission services they neither need nor use. Rate reform is needed to bring PG&E's local transmission and backbone-only rates more closely into conformance with cost of service.
Mirant agrees with PG&E that the continuation of the present single-tier local transmission rate is a problem. If the Commission maintains the status quo, Mirant asserts that this would be the worst and most harmful outcome. Any failure to address this problem will encourage the sort of large user bypass that is of concern to PG&E and other parties.
Mirant points out that TURN's opposition to the backbone-only rate is the risk of creating stranded costs, and appears willing to allow such bypass for new load that did not require past investments in the local transmission system. Mirant notes that TURN correctly recognizes that if a new or expanded load needs to be served, there is at least the possibility that the utility will avoid its own costs of new construction by allowing that customer to build its own lateral to the backbone system. TURN would limit the application of a backbone-only rate to new loads or incremental loads of existing customers, defining new load to include load that has developed since March 1998, and that has always utilized privately constructed facilities to access the backbone system. Mirant believes that the distinction that TURN draws between new load that did or did not require past investments in the local transmission system has merit, because it gets to the heart of the concern about stranding local transmission plant. However, Mirant is not sure why a distinction should be drawn between new load developed since March 1998 and load predating the Gas Accord. Mirant believes that any backbone level load that never required investments in local transmission plant should not be burdened with having to pay local transmission rates.
Mirant contends that ORA's position that all parties should be responsible for paying PG&E's local transmission charges, regardless of whether they benefit from the service or not, is unreasonable. Mirant contends that rate shifting is inevitable because curing an inequity requires some transfer of cost responsibility from those who were unfairly burdened to those who enjoyed an undeserved privilege. To impose a burden of proving that every group of customers will benefit from every rate design proposal would make any rate structure reform impossible.
Mirant recommends that the backbone-level rate structure be adopted. However, if that proposal is not adopted, Mirant favors the PG&E's four-tier local transmission rate proposal over the continuation of the current single-tier local transmission rate.
PG&E proposes to replace the single average local transmission rate for all noncore customers with a declining four-tier rate based on a customer's annual usage for local transmission service. The proposed rate for PG&E's largest noncore customers (Tier 4), which uses 125 million therms or more per year, would be $0.075 per decatherm. For the next largest customers (Tier 3), which have annual usage of 50 to 124.9 million therms per year, PG&E proposes a rate of $0.150 per decatherm. Although there are only 18 customers in PG&E's proposed Tier 3 and Tier 4, throughput to those customers total over 700 Mdth/d.
The Tier 2 noncore customers would include customers with annual loads of 3 million therms to 49.9 million therms. Tier 1 would include customers with annual loads of less than 3 million therms. The local transmission costs that are not recovered from the Tier 3 and Tier 4 customers, due to the establishment of a reduced rate for those customers, are allocated to the core and to Tier 1 and Tier 2 noncore customers on the basis of the currently adopted marginal demand measure for local transmission cost allocation, cold year coincident peak month.
Some of PG&E's largest noncore customers seek backbone-only rates, arguing that they are or could be directly connected to PG&E's backbone transmission facilities. PG&E's four-tier local transmission rate structure is a compromise.
Assuming that 600 Mdth/d of load directly connected to the backbone as a result of the backbone-level rate structure, core local transmission rates would increase by 9.9% over the level that would result from adoption of PG&E's four-tier compromise.
NCGC supports PG&E's four-tier rate design proposal. The proposal is a reasonable measure to mitigate the bypass of the local transmission system and as a compromise alternative to establishing a backbone-only rate. The adoption of a backbone-only rate, rather than PG&E's proposal, would unfairly penalize customers who might have located their facilities closer to the backbone if a backbone-only rate had existed. The failure to adopt PG&E's proposal or a backbone-only rate would encourage PG&E's largest customers to seek an economic alternative to taking service through PG&E.
ORA points out that PG&E's tiered rate proposal is a volume discount mechanism where customers with the highest volume would experience the highest discount, and those in the tiers with lower volume are likely to experience substantial increases in rates. According to TURN's testimony, PG&E's proposal would result in a 46% increase in core rates and an equally large decrease in high volume noncore rates.
ORA asserts that PG&E has not met its burden of proof that the tiered rate structure is justified. Under PG&E's proposal, core customer rates would be adversely impacted. ORA contends that when there is an element of doubt concerning the utility's proposals, that the doubt must be resolved against the utility, and the utility must overcome the presumption that existing rates are reasonable and lawful. (See D.00-02-046 [2 CPUC3d 89, 98-99].) Under § 451, whenever a utility proposes a rate increase, the Commission must make a finding that the proposed rates are "justified and reasonable." ORA contends that the substantial rate increases that would result from PG&E's tiered rate proposal are not justified or reasonable.
Palo Alto is considered a wholesale customer of PG&E. Under the Gas Accord settlement and the extension, Palo Alto and PG&E's other wholesale customers contribute to the local transmission revenue requirement of the noncore class and pay the average local transmission rate for the noncore class. This rate is currently $0.149 per Dth, and reflects an escalated revenue requirement of $153.9 million.
PG&E is proposing to calculate the 2004 local transmission rate for retail core customers and the core portion of wholesale customer loads by creating a core local transmission rate. This rate would apply to all "core" loads in PG&E's service area, regardless of whether the customers are physically connected to PG&E's distribution system or receive service from Palo Alto or other wholesale entities.
PG&E's local transmission rate proposal consists of three simultaneous changes: (1) a large increase in the local transmission revenue requirement based, in part, on the proposed Winter Reliability Standard, which promises larger cost increases in the future; (2) a tiered noncore rate structure intended to mitigate pressure from large customers for a backbone-only rate; and (3) a new methodology for establishing the local transmission rate for wholesale customers.
If PG&E's proposal is adopted, PG&E's local transmission revenue requirement would grow to $179.3 million, an increase of $25.4 million over 2003. Under PG&E's proposal, the revenues allocated to retail core and wholesale core loads would be combined and a single local transmission rate of $0.419 per Dth would apply to both retail core customers and to core wholesale customers. This rate would increase Palo Alto's local transmission rate and revenue requirement in 2004 by approximately 182%, which is far greater than what is proposed for any other customer class. In contrast, the revenue reductions under PG&E's tiered rate proposal for tiers 3 and 4 would be 1.9% and 51%, respectively, from 2003 levels.
Palo Alto contends that the Commission should reject PG&E's local transmission proposal on procedural, policy, and technical grounds. Procedurally, the local transmission proposal of PG&E was not identified as an issue in the scoping memo or in any subsequent rulings.85 On policy grounds, the proposal should be rejected because it violates the Commission's long-standing policy that wholesale customers are part of the noncore class,86 that wholesale customers contribute to the noncore revenue requirement, and that wholesale rates should be based on the wholesale customers' share of the adopted cost allocation factors, not those based on the allocation factors of retail core customers or a co-mingling of retail core and wholesale core shares. Palo Alto asserts that the Commission has never authorized PG&E to combine the core portion of wholesale loads with PG&E's retail core customers for cost allocation purposes, or to charge wholesale customers retail core transmission rates, and should not do so in this proceeding.87 As stated in Conclusion of Law 58 in D.86-12-010, "Wholesale customers should be treated as noncore customers with core load responsibilities."88 (22 CPUC2d 491, 566.) Palo Alto also contends that PG&E's proposal would violate the policy of avoiding rate shock on individual customer classes. PG&E downplayed the rate impact on wholesale customers.
On technical grounds, the proposal should be rejected because it is based on the false assumption that retail core customers are subsidizing the local transmission costs of wholesale customers' core loads,89 and that the proposal disregards the major differences between the cost drivers of retail core customers and wholesale customers.90 Palo Alto contends that lumping retail core and wholesale customers together would disregard the huge differences in costs between core customers and wholesale customers.
SMUD is constructing a new natural gas-fired combined cycle power plant, the first phase of which will generate 500 MW and is scheduled to go on-line in 2005. The second phase of the project will generate another 500 MW, and is scheduled to go on-line in 2008. The first phase will approximately double SMUD's existing gas load of 60,000 decatherms per day (Dth/d), and the second phase will triple SMUD's existing gas load.
SMUD has a 51 mile, 20 inch high-pressure pipeline which connects its plants to PG&E's backbone system. SMUD plans to extend its pipeline by an additional 26 miles to connect to its new plant. SMUD points out that the pipeline was constructed at its own customers' expense, and none of the costs were paid for by PG&E or its ratepayers.
SMUD proposes three changes to PG&E's proposed Gas Accord rate structure. SMUD's first proposal is that the Commission establish an unbundled backbone-level rate structure for gas customers who take service directly from PG&E's backbone transmission system. The second proposal is that the Commission either (1) adopt a load factor based on the volume of capacity sold, rather than adopting PG&E's proposed load factor reduction based on projected throughput, or (2) direct PG&E to sell surplus backbone capacity to SMUD. SMUD's third proposal is if the Commission does not adopt the two proposals, that the Commission amend PG&E's proposed Rule 27 to allow SMUD to receive a credit against the local transmission rates for the cost savings that PG&E customers enjoyed by having SMUD build its own pipeline system to serve its new gas-fired plants rather than having PG&E upgrade its existing local transmission system.
SMUD asserts that a backbone rate would send correct price signals to new electric generators, improve the reliability of PG&E's local transmission system, and reduce the need for PG&E to expand its own local transmission system, thus reducing costs for other ratepayers.
SMUD first raised the backbone rate issue in PG&E's 1994 BCAP proceeding, A.94-11-015. At the time, and before SMUD's pipeline was built, SMUD argued that it should not have to pay for transportation charges to move gas across its own pipeline. In D.95-12-053 at 61, the Commission found that "an unbundled backbone-only rate is consistent with our general direction for the gas industry." D.95-12-053 then opened a second phase of the BCAP to consider the issues associated with implementing a backbone-only rate. SMUD and PG&E then negotiated the sale to SMUD of an undivided interest in PG&E's backbone Lines 300 and 401. The Gas Accord provided that if the sale was not approved before the Gas Accord became effective, that SMUD should receive a discount of about 95% of the PG&E local transmission charge. (73 CPUC2d at 818.) The Gas Accord essentially provided SMUD with a backbone-only rate. The sale to SMUD of the interest in Lines 300 and 401 was approved by the Commission in D.97-04-087. The Commission found in D.97-04-087 that such a sale would provide incremental throughput for the PG&E backbone system and would avoid the stranding of backbone capacity that would occur if SMUD took backbone service on another pipeline. The Commission also found that SMUD would be able to stabilize its long-term costs of transportation and optimize use of its own pipeline facilities, which SMUD constructed at its own expense, saving PG&E millions of dollars in construction costs it otherwise would have incurred. The Commission also found that the lateral to the backbone that SMUD built did not represent bypass of the PG&E's local transmission system, because the PG&E system could not meet SMUD's requirements without substantial expansions.
SMUD points out that TURN supported SMUD's backbone equity purchase. TURN also acknowledges that if the Commission adopts a backbone-level rate structure, it should limit the application of such a policy to new loads or incremental loads of existing customers. Since TURN defines new load to include load that has developed since the start of the Gas Accord period, and which utilizes privately-constructed facilities to access the backbone system, SMUD requests that the Commission define new load to expressly include SMUD's local transmission pipeline system, which was built before the Gas Accord was negotiated.
SMUD's equity capacity in the two lines exceeds SMUD's average daily load, but is below its peak load of 100,000 Dth/d. To the extent SMUD's gas moves through its equity capacity, SMUD does not have to pay for local transport charges across its own local pipeline. However, during high load periods, SMUD has to pay for local transport charges. Once SMUD's new plant comes on-line in 2005, SMUD will be required to pay these local transmission charges on a regular basis, unless the Commission changes the rate structure.
PG&E's argument against a backbone-only rate is that the core and noncore customers who are not directly connected to backbone facilities will pay a larger share of the local transmission costs. SMUD asserts that PG&E's argument is contrary to cost-of-service principles. Customers who take service directly from the backbone system do not use, and should not have to pay for PG&E's local transmission or distribution systems.
SMUD points out that PG&E's prepared testimony describes a local transmission customer as "situated anywhere from 5 feet to 150 miles from PG&E's backbone facilities." (Ex. 1, p. 14-21.) Since SMUD's pipeline facilities are connected directly to PG&E's backbone, SMUD does not fit within that definition because it is located zero feet from the backbone. SMUD argues that if the Commission does not adopt a backbone-only rate, under PG&E's definition, SMUD should not be considered a local transmission customer and should not have to pay local transmission charges. SMUD contends that the only charges that should be collected from SMUD are the customer access charge expenses to administer SMUD's account.
SMUD contends that the most important beneficiaries of a backbone-only rate would be the 1.3 million people served by SMUD in a service territory of 900 square miles in the greater Sacramento area. If PG&E's rate structure remains the same, SMUD's customers would be charged for services that they do not use.
Customers that take service directly from the backbone system do not use, and should not have to pay for, PG&E's local transmission or distribution systems.
TURN recommends that the Commission reject the proposal of CCC/Calpine for a backbone-only rate, or at a maximum, allow bypass only for new load that did not require past investments by PG&E in the local transmission system.
CCC/Calpine propose that the Commission establish a backbone-only rate for customers who connect directly to PG&E's backbone. They argue that such a proposal is justified and consistent with cost-causation principles because backbone customers do not create costs on the local transmission system.
Currently, about 19 customers are connected to PG&E's backbone. Approximately four of these customers have connected to the backbone since the start of the Gas Accord.
TURN points out that the cost-causation argument of CCC/Calpine only applies to the incremental load which has never taken service from the local transmission system. A customer who currently takes service from the local transmission system and bypasses this system only in order to take advantage of a backbone-only rate has already contributed to the fixed costs of the local transmission system, since the system was designed to provide full service to all existing customers. If a customer bypasses the local transmission system, the rates of all remaining customers (core and noncore) would have to increase to make up for the lost local transmission revenues. When the throughput forecast is adjusted in the next BCAP proceeding, the rates of core customers would increase due to reduced noncore throughput. TURN estimates that the annual revenue loss associated with the bypass of local transmission could be as high as $32.5 million.
TURN contends that allowing customers who are currently served from the local transmission system to build laterals to bypass the local transmission system is unnecessary and may impose significant costs onto the remaining ratepayers. Those existing customers' needs are adequately served from the local transmission system interconnects.
The CCC/Calpine witness concluded that a backbone-only rate will increase core rates less than PG&E's tiered rate proposal for local transmission. TURN points out, however, that the analysis of CCC/Calpine assumes that no customers, who are currently connected to the local transmission system, will choose to build a lateral to the backbone. The analysis by the CCC/Calpine witness assumed that only the load connected to the backbone will qualify for the backbone-only rate, which results in a CCC/Calpine forecast of backbone load which is about one-fourth that of PG&E's forecast. TURN contends that if a backbone-only rate is adopted, the potential customers and associated load, and the resulting cost shift, is likely to be much greater than what CCC/Calpine assumed.
TURN asserts that before a backbone-only rate is adopted, the Commission must consider the unbundling that has already taken place, before it decides if there should be further unbundling of the system. TURN asserts that it is not clear that California will be better off if it replaces the integrated gas utility system with a series of privately-owned laterals to serve specific customers. Serious issues of facility duplication and economic waste are raised by such a policy. In addition, the siting of future power plants may be done on the basis of proximity to a backbone pipeline, rather than to a load center.
In the event the Commission adopts a backbone-only rate, TURN recommends that it only apply to new loads or the incremental loads of existing customers. Customers who have taken service from the local transmission system historically, should not be eligible for any backbone-only rate. This will avoid the problem of an existing local transmission customer selecting the backbone rate in order to obtain a lower rate, which will then result in stranded costs being shifted to the remaining ratepayers.
If the Commission chooses to adopt a backbone-rate for all customers with a corresponding charge for "stranded costs," TURN recommends that a separate phase of this proceeding be implemented to address the stranded cost calculation.
TURN does not agree with the argument of CCC/Calpine that the reasoning in the Praxair resolution supports their contention that customers with existing connections to the local transmission system should be allowed to bypass. The Praxair situation found that the potential cost shift was not large. This is in contrast to a potential cost shift of over $30 million if 12 out of the 18 largest noncore customers of PG&E choose to bypass the local transmission system.
PG&E proposes to increase the total annual local transmission revenue requirement from $153.89 million (2003) to $179.263 million (2004), an increase of $25.373 million. (Ex. 76.) Part of the increase is due to the costs of local transmission upgrades associated with the Winter Reliability Standard to provide the noncore with an increased reliability standard. However, PG&E's cost allocation proposal also assigns more of the increase in the local transmission revenue requirement to core customers. Under PG&E's cost allocation proposal, the core's portion of the local transmission revenue requirement would increase by $36.201 million (from $87.242 million in 2003 to $123.443 million in 2004), while the noncore would enjoy a $10.828 million reduction (from $66.648 million in 2003 to $55.820 million in 2004) in its allocation of the local transmission revenue requirement. TURN notes that although noncore rates decrease, a portion of the increase is due to the costs of local transmission upgrades that are necessary to provide the noncore with increased reliability under the Winter Reliability Standard.
TURN contends that PG&E's rate proposal violates Commission precedent and policies, is contrary to generally accepted methods of cost allocation and rate design, and violates PG&E's prior representations before the Commission. PG&E's methodology did not follow generally accepted methods of cost allocation and rate design because the total local transmission revenue requirement of $179.263 million was not allocated properly among the customer classes using the appropriate allocation factor. According to TURN, the costs should have been allocated to the core and noncore customers before rates were determined.
TURN asserts that the rates for tier 3 and tier 4 customers were arbitrarily set. PG&E did not use cost of service, value of service, long-run marginal costs, short-run marginal costs, embedded costs or incremental costs to calculate the revenue requirement for tiers 3 and 4. As a result, PG&E's proposal will cause a 40.5% increase in the core's revenue requirement allocation. Wholesale customers, such as Palo Alto, will experience a 181.4% increase in the local transmission revenue requirement allocation.
Currently, retail core customers pay $.287 per Dth for local transmission, about 1.97 times the $0.149 per Dth that noncore retail customers pay. Under PG&E's proposal, the core rate would increase by 46% to $0.419 per Dth, while the average noncore rate would drop to $0.128 per Dth. Thus, the new core rate would be approximately 3.8 times more than the average new noncore rate.
If PG&E were to extend the existing Gas Accord cost allocation methodology into 2004, the core's portion of the local transmission revenue requirement would be $114.538 million with core wholesale, or $112.969 million without core wholesale. The noncore's portion would be $66.294 million with core wholesale or $64.725 million without core wholesale. The core would pay $0.389 per Dth, and the noncore would remain unchanged at $0.149 per Dth. Although this represents a rate increase of 35.6% for the core, TURN contends that such a result would be preferable to PG&E's proposal.
PG&E's rationale for its proposed cost allocation is to discourage large noncore customers, who are located near PG&E's backbone facilities, from seeking a backbone-only rate. However, TURN contends that these savings in local transmission rates for tiers 3 and 4 will allow these customers to use the savings to construct facilities to tap into PG&E's backbone system, and to further advocate for a backbone-only rate. TURN asserts that PG&E's proposal creates a subsidy for PG&E's wealthiest customers, and shifts a considerable burden onto core customers in a futile effort to prevent large customers from seeking a backbone-only rate.
PG&E has offered an economies of scale argument in support of its four-tier local transmission rate proposal. TURN points out, however, that the economies of scale argument did not serve as the basis for PG&E's proposed local transmission cost allocation. Instead the proposed allocation resulted from "hard-wiring" the cost allocations to noncore tier 3 and tier 4 at arbitrary levels. After that, PG&E apportions revenue responsibilities between noncore tiers 1 and 2, and the core, according to its marginal demand measure. TURN asserts that this is an improper and unprecedented method of arriving at rates.
TURN contends that the use of an allocation factor is the proper tool to allocate costs between the customer classes. Once the utility has set a revenue requirement ($179.263) for a function, the next step is to multiply the allocation factor assigned to each customer class by the total revenue requirement. The products of these calculations are the respective responsibilities for the revenue requirement of each customer class, upon which rates are based. Such a process allows the utility to compete more effectively for noncore customers, and it also protects the core from the utility forcing it to bear any revenue shortfalls that result from the utility's contracts with noncore customers. PG&E's proposed local transmission cost allocation directly contradicts this, and improperly attempts to protect revenues by forcing the core to pay rates that reflect revenue that it may not get from those geographically well-situated noncore customers in tiers 3 and 4.
TURN also argues that PG&E's application violates § 739.7 because it will increase the core's baseline rates for the explicit purpose of subsidizing a handful of wealthy noncore customers in tiers 3 and 4, with no corresponding decrease in core non-baseline rates.
TURN suggests that if a higher standard of reliability for noncore service is adopted, the Commission should consider moving from a cold-year peak month allocater to a cold-year non-coincident peak month measure. TURN contends that such a methodology would better capture the impact on the system of those noncore customers whose maximum usage occurs in a month other than January.
PG&E has marketed its four-tier local transmission proposal as constituting the lesser of two evils, i.e., a backbone-only rate versus PG&E's cost allocation and rate design. TURN points out that the third alternative is to simply maintain the existing Gas Accord structure and cost allocation methodology. A fourth alternative is to create tiered rates within the noncore customer class and to maintain the Gas Accord cost allocation between noncore and core.
PG&E recommends that the Commission adopt PG&E's four-tier declining local transmission rate proposal, and that the proposal of CCC/Calpine and SMUD for a backbone-level rate structure be rejected. The backbone-level rate structure issue involves the interests of some generators who are located near PG&E's backbone transmission facilities, which needs to be balanced with the interests of 3.8 million core and noncore customers. PG&E contends that the 3.8 million customers will not benefit from the backbone-level rate structure proposal, and would end up paying higher rates. PG&E recommends that the Commission adhere to its long-standing policy of non-bypassable local transmission charges for all customers.
PG&E asserts that its four-tier noncore local transmission rate proposal offers a rate compromise to large or well-situated generators and customers such as Calpine, CCC, CMTA and Mirant, compared to the single average non-bypassable noncore local transmission rate that exists today. PG&E contends that its proposal moves local transmission rates closer to the cost of service for each specific noncore customer segment, while balancing customer concerns for higher rates that would occur under a backbone-level rate structure.
PG&E's proposal recognizes that all customers, including core customers, must bear some of the additional cost responsibility from a rate structure that may mitigate or discourage Tier 3 and Tier 4 customers from seeking a backbone-level rate structure. PG&E's proposal offers a compromise between the full averaged noncore rates of today and rates that better reflect the cost of providing the service.
PG&E acknowledges that its local transmission cost allocation and rate proposal results in increases for certain smaller noncore and core customers. However, these increases are not nearly as high as they would be under the backbone level rate structure.
PG&E's studies suggest that 600 MDth/d or more of load potentially qualify for backbone-only rate treatment. Under the proposed backbone-level rate structure, core and noncore customers who remain on local transmission facilities could pay local transmission rates that are 25 to 61% higher than rates today as shown in Table 14-2 of Exhibit 4. PG&E contends that the impacts of a backbone-only rate will grow over time, and cannot be reviewed based solely on current backbone-level connections.
The proponents of the backbone-only rate fail to take any responsibility for the revenue loss or the underutilization of local transmission facilities that could result. If noncore customers who connect directly to the backbone, are no longer required to pay the local transmission rate, PG&E would receive less revenue from those customers, while the revenue responsibility of other customers would increase.
PG&E notes that PG&E's noncore customers are "a diverse group, ranging from about 785 customers who use less than 3 million therms per year to a small number of large electric generators and refineries that use more than 125 million therms per year." (Ex. 3, p. 1-15.) With the variations in size and demand patterns, the actual cost to serve individual noncore customers varies substantially, and some noncore customers are well situated either to connect directly to PG&E's backbone facilities or to bypass PG&E's system entirely. PG&E's proposed four-tiered rate structure is segmented by annual usage, and reduces local transmission rates for the largest noncore customers while moderately increasing rates for core and small noncore customers.
PG&E states that its studies demonstrate that economies of scale are a primary consideration in examining the costs to serve large Tier 3 and 4 customers. PG&E's studies indicate that the cost to serve 35% of the Tier 4 load is below 7.5 cents per dth. Since Tier 4 customers have loads that are 2.5 to 12 time greater than Tier 3 customers, their rate per unit is significantly lower, reflecting the economies of scale.
PG&E points out that its segmented noncore local transmission rate design is similar to the electric generator rate segmentation that was adopted for SoCalGas, and complies with § 454.4, as interpreted by the Commission in D.00-04-060.
PG&E points out that if the proposal for a backbone-only rate for customers who are directly connected to the backbone is adopted, there is the possibility that cogeneration customers might be entitled to the same backbone-only rate under the parity rights in § 454.4. If the cogenerators were successful, this would increase the load qualifying for the backbone-only rate by an additional 265 MDth/d. If 865 MDth/d (600 MDth/d plus 265 MDth/d) or more of load were to qualify for backbone-only rate, local transmission rates will increase substantially for all remaining core and noncore customers. As the rate differential between backbone-only rates and backbone plus local transmission rates widen, the incentive increases for additional customers to build connections to the backbone. PG&E's four-tier proposal is reasonable since it moves noncore rate levels closer toward the cost of service, while continuing the Commission's policy of non-bypassable local transmission rates and a revenue responsibility that is shared by all customers.
PG&E asserts that a backbone-level rate structure would discriminate against those who have made economic decisions to site facilities away from PG&E's backbone facilities. Since existing customers do not have a choice in their service level, PG&E contends that it would be discriminatory to set rates based on the geographic location of one facility over another. PG&E also states that such a structure would also encourage large or well-situated gas customers to build gas pipeline laterals to connect to the backbone facilities, which would inefficiently duplicate existing PG&E facilities.
PG&E also points out that rate designs are not based solely on service-level cost causation. Instead, other factors, such as compliance with § 454.4 or core service reliability, can cause customers to pay for facilities that they do not necessarily use. The Commission's policy is to set average cost rates, not exact cost rates.
TURN criticized PG&E's proposed local transmission cost allocation and rate design because PG&E did not offer a sufficient reason to deviate from the established methodology. PG&E points out that its local transmission rate proposal is designed to discourage uneconomic bypass by substantially reducing the economic incentive for those customers who desire a backbone-only rate. It moves the local transmission rates closer to the cost of service for each specific noncore customer segment while balancing customer concerns for higher rates that would occur under a backbone level rate structure. PG&E contends that the continued use of the existing local transmission cost allocation and rate design methodology for noncore customers will not remove the incentive for certain large or well-situated customers to seek a backbone level rate alternative. The CCC/Calpine witness agreed that if a backbone-only rate is not adopted, and the four-tier rate is adopted, that this would be an improvement for his clients over the local transmission rate levels they pay today.
The cities of Palo Alto and Coalinga pay noncore local transmission rates as part of the Gas Accord Settlement Agreement. PG&E recommends that this treatment not be continued in 2004. Instead, these wholesale customers should pay core local transmission rates on behalf of core customer loads they serve and pay noncore local transmission rates on behalf of the noncore customer loads they serve. PG&E's proposal to charge wholesale core customers the core local transmission rate correctly aligns rates with the level of service reliability that wholesale core customers receive. If PG&E's proposal is not adopted, this will continue the inequitable situation which forces core retail customers to subsidize the local transmission rates paid by core wholesale customers.
PG&E points out that wholesale customers can agree to take service at the lower noncore rate. However, this would reflect service at the noncore's level of reliability. It would also mean that they would not receive the core's abnormal peak day reliability, or the rights to vintage core Redwood capacity.
PG&E contends that its local transmission rate proposal for wholesale customers is consistent with D.86-12-005 because it eliminates the current local transmission cost subsidy paid by core retail customers on behalf of core wholesale customers. PG&E proposes to charge core wholesale customers the core local transmission rate, consistent with the core vintage backbone rates they receive. PG&E proposes to charge noncore wholesale customers the noncore local transmission rate, consistent with the noncore backbone rates they pay.
PG&E opposes the proposal of TURN, ORA and Palo Alto to simply extend the 2003 local transmission rates. Such an extension will not allow PG&E to recover its local transmission cost of service, and does not recognize the differences in cost of service for customers. Although all costs could be recovered for 2004 with a single-tier rate design, PG&E contends that such a design provides an incentive for certain customers to continue to seek a backbone-level rate structure, or other transportation alternatives.
Palo Alto's claim that wholesale customers' local transmission rates were not being subsidized during the Gas Accord period is flawed and without merit. PG&E contends that the table in Exhibit 55 demonstrates that the local transmission marginal cost unit rate to serve wholesale customers is higher than the local transmission marginal cost unit rate to serve core customers. Also, the wholesale unit rates are more than twice the unit rates to serve noncore retail customers. Since core wholesale customers have been paying the noncore retail local transmission rate during the Gas Accord period, wholesale core customers receive a significant local transmission rate subsidy, compared to their underlying cost of service. The difference between their rate and cost of service is allocated to core retail customers.
PG&E's proposal regarding wholesale customers would result in less than a dollar per month increase to the typical residential customer in Palo Alto's service territory, and approximately a $1.35 per month increase to the typical residential customer in Coalinga's service territory. PG&E contends that the proposed local transmission charge amounts to only a fraction of the burnertip cost of gas for end-use customers.
TURN contends that if a higher standard of reliability for noncore service is adopted, local transmission cost allocation should be done on the basis of a cold year non-coincident peak month measure. PG&E asserts that TURN's contention is without merit because cost allocation based on a cold year coincident peak month already represents a less extreme demand measure than strict cost causation principles such as cold winter day or abnormal peak day, and allocates costs in an equitable manner to core and noncore customers. PG&E asserts that the cold year coincident peak month continues to be the appropriate marginal demand measure for local transmission cost allocation between core and noncore customers.
Local transmission facilities consist of non-backbone facilities with design operating pressures greater than 60 pounds per square inch gauge. Under the current Gas Accord structure, all on-system end-use customers are obligated to pay local transmission rates.
The backbone-level rate structure is discussed in this section because the proposal, if adopted, would eliminate the responsibility of customers who are directly connected to PG&E's backbone from having to pay local transmission charges. Gas consumers located near interstate pipelines have sought to connect to those pipelines to avoid having to pay PG&E's local transmission charges. Requests for a backbone-only rate have come before the Commission previously. (See D.95-12-053 [63 CPUC2d 414]; D.01-05-086.)
To address the potential bypass of PG&E's gas transmission facilities, PG&E proposes that a declining four-tier local transmission rate structure be adopted in 2004 for noncore customers. CCC/Calpine, Mirant, and SMUD propose that the Commission authorize a backbone-level rate structure, which would permit an end-user to connect directly to PG&E's backbone transmission system, and avoid having to pay any local transmission charges. Other parties advocate that the current allocation method be used, i.e., a single average rate for noncore, including core wholesale, and a core retail rate, for 2004.
The common thread among the parties who favor or oppose these proposals is whether or not the proposals will be of financial benefit or harm to them.
The purpose behind PG&E's proposal is to provide a financial incentive for large customers, who are considering a bypass of PG&E's transmission facilities, to remain on the system because of lower local transmission charges. The backbone-level rate proposal will allow those customers who are located in close proximity to PG&E's backbone to take backbone service, and to avoid any local transmission charges.
Under PG&E's proposed four-tier rate structure for noncore customers, core wholesale customers, such as Palo Alto and Coalinga, would be treated as core customers. Under the current Gas Accord structure, core wholesale customers pay the noncore single average rate of $0.149 per Dth. Under PG&E's proposed rates for 2004, core wholesale customers would have to pay $0.419 per Dth.
Core customers currently pay $0.287 per Dth for local transmission. Under PG&E's proposal, the 2004 rate for core customers would rise to $0.419 per Dth.
TURN presented evidence of what the rate impact would be if the current cost allocation methodology were to remain in place using PG&E's proposed local transmission revenue requirement. Under such a scenario, the core would pay $0.389 per Dth in 2004, and noncore would remain unchanged at $0.149 per Dth.
Under PG&E's four-tier proposal, noncore customers would be split into four-tiers, based on usage size. Under PG&E's proposal, the two lower tiers of noncore customers would pay higher rates than the higher tier customers. Under the present structure, all noncore customers pay a single average rate of $0.149 per Dth.
The current and PG&E's proposed local transmission rates are shown in Table 14.1-11 of Exhibit 3.
PG&E estimates that approximately 600 MDth/d of load could qualify for backbone-only rates.91 Assuming this entire load connects to PG&E's backbone, the remaining core and noncore customers could pay local transmission rates that are 25 to 61% higher than rates today as shown in Table 14-11 of Exhibit 3 and Table 14-2 of Exhibit 4. In those tables, core rates in 2003 would go from $0.287 per Dth to $0.463 per Dth. Noncore rates in 2003 would go from $0.149 per Dth to $0.187 or $0.229 per Dth depending on the tier. The impact of a backbone-only rate could also grow over time as more end users connect to the backbone or bypass PG&E's system.
If the backbone-level rate structure is adopted, the CCC/Calpine witness developed recommended local transmission rates for 2004. Assuming that 54 MMDth/d of noncore load will be served directly from the backbone, CCC/Calpine recommend a core local transmission rate of $0.398, and a noncore local transmission rate of $0.181.
It is clear from the above examples of the cost impacts that the proposals of PG&E and CCC/Calpine will shift the cost burden onto the core and the other customers who are not in a position to bypass the system. In addition to the cost impacts, these two proposals raise the fundamental issue of who should pay for the cost of facilities to serve customers.
When the backbone-only rate came before us in 2001, we stated in D.01-05-086 that the request to avoid the local transmission charge "would cause substantial cost shifting which involves complex policy choices, as to which numerous parties have divergent interests and points of view." The decision also noted that: "The relief requested would provide more favorable treatment to specific merchant power plants that would obtain a distinct competitive advantage over other merchant generators in California by avoiding payment of local transmission charges which all other on-system merchant generators must pay." (D.01-05-086, p. 18.)
We also stated in D.01-05-086 that the issue of the backbone-only rate should be deferred to Gas Accord II, which began January 1, 2003. Although the backbone-only rate, and PG&E's four-tier proposal are now before us, we do not believe this is the appropriate time to adopt either of the proposals.
We also note that TURN raised the issue that if a higher standard of reliability for noncore service is adopted, local transmission cost allocation should be done on the basis of a cold year non-coincident peak month measure. Since we do not adopt the Winter Reliability Standard, TURN's suggestion is moot.
Our first reason for not adopting either of the two proposals is because core customers, customers who use less gas, core wholesale customers, and customers who are not in a position to directly connect to the backbone will be harmed the most. Under the backbone-only rate, CCC/Calpine envisions that the current core rate of $0.287 per Dth will increase to $0.398 in 2004. The core rate could go as high as $0.463 per Dth if PG&E's estimate of backbone-level migration proves correct. Noncore customers, under the backbone-level rate structure, would experience an increase from $0.149 to a range of $0.181 to $0.229. Core wholesale customers, under PG&E's proposal, would be treated the same as a core customer and would see their rates rise from $0.149 per Dth to $0.419 per Dth in 2004. Under PG&E's proposal, the smaller customers in tiers 1 and 2 would see their rates increase from $0.149 to either $0.154 or $0.201.
In contrast, under the backbone-only rate, customers connected to the backbone would avoid all local transmission charges. Essentially, the costs that these customers avoid, will be shifted to the remaining customers, raising their rates.92 Under PG&E's proposal, the new Tier 3 customer would see a slight increase from $0.149 to $0.150, and the new Tier 4 customer would experience a lowering of the rate from $0.149 to $0.075. Under both proposals, the largest customers, or those able to connect to the backbone, benefit.
The resulting cost shift is not equitable. As PG&E's witness acknowledged, under the four-tier proposal, the core is burdened with more than 75% of the overall revenue requirement increase. (9 RT 999-1001.) Under the backbone-only rate, core rates would go up by at least $0.11 per Dth. Given the increases to the core, core wholesale, and to the smaller noncore customers, we do not believe that the rates proposed by PG&E or CCC/Calpine would be just and reasonable.
We also do not agree with PG&E that the six wholesale customers who serve their own customers should be treated as a core customers for the purpose of local transmission charges. Although they enjoy certain benefits of being a core customer, as Coalinga and Palo Alto point out, they also have attributes which clearly distinguish them as noncore. As noted in Conclusion of Law 58 in D.86-12-009, "Wholesale customers should be treated as noncore customers with core load responsibilities." (D.86-12-010 [22 CPUC2d at 566]; See D.86-12-009 [22 CPUC2d 444, 478-479].) There is no compelling reason to consider treating wholesale customers differently after more than 15 years.
The second reason for not adopting the backbone-level rate structure or PG&E's four-tier rate proposal is there are complex policy issues that must be considered. (D.01-05-086, p. 18; D.95-12-053 [63 CPUC2d at 451].) As PG&E noted, the backbone-level rate structure issue, as well as PG&E's four-tier rate structure proposal, involves the interests of some generators who are located near PG&E's backbone transmission facilities, and the interests of 3.8 million core and noncore customers. Although we are cognizant of the benefits that the electric generators provide, the interests of millions of other customers must also be considered. Even CCC/Calpine acknowledge in their reply brief that "as a matter of social policy, the Commission may choose to provide subsidies to one class of customers at the expense of others ..." and that it is "difficult to eliminate all subsidies from rates, and that rate averaging will be, to some extent, necessary." (CCC/Calpine, Reply Brief, p. 30.)
The four-tier proposal represents a stop-gap measure to prevent certain customers from bypassing the PG&E system. Even if we adopt PG&E's proposal, it is likely that further discounts will be sought, and the backbone-only rate will still remain an issue.
Both proposals require careful thought of how far we want to unbundle the backbone from local transmission, and who will end up paying for the cost of local transmission. Adopting the four-tier rate structure or the backbone-only rate at this point will only result in the shifting of more costs onto the remaining customers. With the uncertainty of what will happen with the regulatory jurisdiction over PG&E's transmission system, we are not prepared today to decide whether those customers who connect directly to the backbone should be able to avoid local transmission charges.
Although CCC/Calpine contend that resolution of the backbone-only rate is long overdue, the balancing of higher rates for the majority of customers, versus lower rates for a small number of customers, clearly weighs in favor of not adopting the proposals which would increase rates for the majority of customers.
Accordingly, the backbone-level rate structure proposal is not adopted. Furthermore, PG&E's four-tier rate proposal for local transmission is not adopted.
To develop PG&E's 2004 all volumetric local transmission rates, PG&E shall use the existing cost allocation and rate design methodology from the Gas Accord. Wholesale customers shall be treated as noncore. A single average rate for core, and a single average rate for noncore, shall be used. Local transmission rates shall continue to be paid by all on-system end-use customers, and shall continue to be non-bypassable. Our adopted local transmission rates appear in Table 11 of Appendix A.
We will permit the parties to raise the backbone-level rate structure in the 2006 gas market rate structure proceeding for PG&E. By that time, the jurisdictional issue should be resolved, and we can then consider a backbone-level rate structure in the context of the gas market structure that we will be adopting. Parties advocating such a rate structure in that proceeding should develop proposals to address the kinds of concerns we have expressed above, and which appear in D.95-12-053 (63 CPUC2d at 451) and in D.01-05-086 at pages 17 and 18.
DGS asserts that PG&E's proposal to make changes to the electric generators and cogenerators will result in the transfer of substantial costs from variable rates to fixed rates. For example, Table 14.1-12 in Exhibit 1 demonstrates that a noncore customer using 20,833 therms per month will experience a customer charge increase of 207%. DGS believes that these costs should be collected as a volumetric charge, collected on an equal cent per therm basis from all users, rather than included in the customer access charge. Also, moving costs from volumetric to fixed customer charges does not encourage conservation because the customer charge cannot be avoided.
Mirant recommends that the Commission reject the drastic and unsupported increases in customer access charges that PG&E has proposed.
PG&E proposes to revise its rate structure and rates for customer access charges. For large electric generator customers, PG&E's plan to convert from volumetric to fixed monthly charges, while adding two volume-defined tiers at the upper end, will produce greatly increased monthly charges. For example, an electric generator customer using 15 million therms of gas per month would face a customer charge increase from $12,000 to $19,600 per month, a 63% increase. An electric generator customer using 30 million therms of gas per month would face a customer charge increase from $24,000 to $43,000, an increase of 79%.
The CCC/Calpine witness, which Mirant co-sponsored, criticized PG&E's customer access charge proposal because PG&E's proposal is premised on the assumption of escalating capital expenditures to install metering on new power plants (from $1.6 million in 2001 to $5.1 million in 2004). Beach testified that this assumption is inconsistent with the recent slowdown of new power plants in the western United States. To align PG&E's customer access expense estimates with PG&E's own revised forecast of new power plant interconnections, Mirant recommends that the Commission adopt customer access charges based on capital additions of $2.5 million in 2002 and $1 million in each of 2003 and 2004.
Mirant agrees with NCGC's recommendation to defer PG&E's customer access charge proposal to the 2005 test year rate case to allow for further analysis. As noted by NCGC witness Pretto, PG&E's proposal would increase customer access charges by over 100%. NCGC also contends that PG&E has failed to justify deviating from precedent to impose fixed monthly customer access charges on electric generator and cogeneration customers, and has failed to explain how the proposed rate tiers were determined. Since PG&E has not justified its proposals, Mirant recommends that PG&E's proposals be rejected.
PG&E proposes to increase the revenue requirement associated with transmission-level customer access charges by over 100%. Current customer access charges recover approximately $6.4 million per year. Under PG&E's proposal, the revenue requirement for customer access charges would increase to $13.6 million for 2004. NCGC recommends that PG&E's proposed increase in the customer access charge revenue requirement be examined further and deferred to PG&E's test year 2005 rate case.
NCGC points out that PG&E's proposal to impose fixed monthly access charges on electric generators and cogenerators will increase the amounts paid by electric generators and cogenerators to cover access charge costs each month. The current all-volumetric access charge rate design for electric generators and cogenerators was adopted in PG&E's 1998 BCAP in D.98-06-073. The all-volumetric rate design was continued in PG&E's 2000 BCAP and has remained in place until now. Currently, the volumetric access charge component of electric generator and cogenerator rates is $0.0008 per therm. Electric generators and cogenerators pay that charge multiplied by the volumes that the customer uses on any given month.
NCGC asserts that the imposition of fixed monthly access charges will conflict with the all-volumetric rate design that has been in place for electric generators and cogenerators on the PG&E system since 1998, and it will conflict with the all-volumetric rate design that has been in place for electric generators and cogenerators on the SoCalGas system for many years. NCGC asserts that PG&E has provided no justification for deviating from precedent, and imposing the burden of fixed monthly access charges on electric generators and cogenerators. PG&E's proposal to impose fixed monthly access charges on electric generator customers should therefore be rejected.
PG&E also proposes to add two higher tiers to the six tiers of customer access charges currently set forth in Schedule G-NT for industrial customers. NCGC contends that PG&E has provided no explanation or justification for switching to an eight-tier structure for industrial customer access charges. PG&E has not explained how the tier values were selected, or how the volumetric parameters for the eight tiers are tied to the underlying service, regulator, meter costs, if there is any tie at all. In light of PG&E's failure to justify any of the details of the eight-tier structure, PG&E's proposal should be rejected.
Several parties have suggested that PG&E's proposed increase in the customer access charge is too high. PG&E contends that the evidence shows that customer access charges are too low, and does not fully cover the full cost of providing service to serve a significantly greater number of customers that PG&E serves today. The proposed increase was developed using a separate embedded cost of service study based on PG&E's experiences over the Gas Accord period, and the estimated facilities and operations costs in 2004.
Some parties advocate that the customer access charge issue be deferred. PG&E contends that deferring this issue will prevent PG&E from recovering its full cost of service.
PG&E proposes to revise the transmission-level customer access charges to reflect the updated revenue requirement. PG&E proposes to continue the existing rate design methodology for industrial and wholesale customers for 2004. PG&E also proposes to add two higher usage tiers to the six-tiered industrial (Schedule G-NT) access charge, and apply the rate structure to all cogenerators and electric generators. PG&E also proposes to update the customer access charges for the core wholesale customers.
With regard to the updating of the customer access charges to reflect the revenue requirement, some of the parties contend that the amount requested is too high and should be deferred for further investigation. Some of the parties believe the customer access charges should be reduced to reflect the lower number of new plant connections. As discussed elsewhere in this decision, we have reduced the power plant connections and power plant metering costs. Since the O&M expenses and capital expenditures were at issue in this proceeding, resolution of the customer access charges will not be deferred.
PG&E contends that the increase in the customer access charges are needed because the current charges do not reflect the cost to provide service. None of the other parties presented any evidence to show that the growth in connections of electric generators over the last seven years has not raised PG&E's costs to connect these additional customers.
The next issue is whether two additional tiers should be added to the six tiers of access charges that are currently set forth in Schedule G-NT. Under PG&E's proposed customer access charges, shown in Table 14.1-12 of Exhibit 3, the rates for these new tiers would go from $3,892.38 to $19,615.11 for Tier 7, and to $43,148.69 for Tier 8. The other six tiers would see their rates increase by approximately 100%.
These two new tiers, along with Tier 6, will bear the brunt of the increases if these additional tiers are added. Aside from PG&E's prepared testimony regarding the customer access charges, PG&E has not provided any other citations to the record in this proceeding in support of the additional two tiers. (See PG&E Opening Brief, pp. 64-66, 97.) PG&E has not provided sufficient evidence to support its proposal to add Tiers 7 and 8 to Schedule G-NT. Therefore, PG&E's proposal to add these two tiers is not adopted.
Unfortunately, transmission-level customer access expenses have gone up, and that burden will be spread to the six tiers and to wholesale customers.
PG&E's other proposal is to apply the customer access charges in Schedule G-NT to electric generators and cogenerators, who will take service under Schedule G-EG. Currently, electric generators and cogenerators are charged an all-volumetric access charge is $0.0008 per therm. Under PG&E's proposal, electric generators and cogenerators would pay a fixed customer access charge, instead of a volumetric charge. Under the fixed charge, an electric generator or cogenerator could end up paying more than it would under the existing volumetric charge. (9 RT 981-982.)
NCGC points out that this volumetric charge was proposed by PG&E and adopted in PG&E's 1998 BCAP in D.98-06-073 (80 CPUC2d 604), and continued in the 2000 BCAP in D.01-11-001. Although the volumetric customer access charge was developed in PG&E's BCAP, this is an appropriate place to consider PG&E's proposal to apply the rates in Schedule G-NT to Schedule G-EG since one of PG&E's other proposals is for a single electric generation class.
We have considered the concerns of Mirant and NCGC. The cost of service for transmission-level customer access has been reduced as a result of the adjustment to power plant connections and metering. Unfortunately, the customer access expenses have increased over the years as new electric generation customers were added. We will adopt PG&E's proposal to apply the Schedule G-NT customer access charges, as revised in this decision, to all cogenerators and electric generators instead of the volumetric customer access charge.
PG&E shall be permitted to update its cost of service for transmission-level customer access to reflect the cost of service as adopted in today's decision. PG&E shall continue to use the existing six-tier structure for Schedule G-NT access charges, including the existing cost allocation, and shall apply those customer access charges to all cogenerators and electric generators. PG&E shall continue to use the existing cost allocation for wholesale customer access charges, which reflects the adopted costs of service and adjustments.
The adopted customer access charges are shown in Table 12 of Appendix A.
TURN supports PG&E's proposal to collect the distribution revenue requirement through a distribution rate component in the customer class charge for the industrial transmission customer class. TURN points out that the distribution costs attributable to these industrial customers are not paid by them, but are instead shifted to other distribution-level customers and PG&E shareholders. TURN contends there is no justification for this subsidy, which was approved as a detail of the Gas Accord settlement.
PG&E proposes that the distribution costs allocated to distribution-level customers served from transmission-level rate schedules be recovered through a distribution rate component in the customer class charge for the industrial transmission customer class. PG&E states that this proposal will result in a slight increase in rates for industrial transmission customers, and a slight decrease in rates for all remaining distribution-level customers.
Prior to the Gas Accord, the distribution costs attributable to industrial transmission customers were collected through a distribution rate component in the rates paid by all industrial transmission customers. The Gas Accord eliminated this distribution rate component, and reallocated the costs to all remaining distribution-level customer classes. In D.98-06-073, a settlement was reached where the treatment of distribution-level costs allocated to industrial transmission customers was allocated 50% to PG&E's shareholders, and the other 50% was allocated to the other distribution-level customer classes for the remainder of the Gas Accord. D.02-08-070 extended this rate treatment through 2003.
TURN is in favor of PG&E's proposal to impose a distribution rate component on the industrial transmission customer class. No one opposes the proposal.
We adopt PG&E's proposal to impose a distribution rate component on the industrial transmission customer class in order to recover the distribution costs allocated to this class. This change will align the costs with the customer class that should pay for it, instead of having such costs subsidized by a different customer class and by PG&E's shareholders.
PG&E also proposes that the cogeneration distribution shortfall account be eliminated, and that the distribution costs allocated to cogeneration customers93 be recovered through a distribution rate component in the customer class charge paid by cogeneration and electric generator customers. In the Gas Accord, the distribution rate component was removed, and these distribution costs were collected from cogeneration and UEG end-users through the cogeneration distribution shortfall rate component in the customer class charge. PG&E contends there is no rate impact from this proposal on any customer class.
No one opposes PG&E's proposal to eliminate the cogeneration distribution shortfall rate component in the customer class charge, and to replace it with a distribution rate component in the customer class charge. We adopt PG&E's proposal.
The rate components which make up the customer class charge will be determined in the BCAPs and Annual True-ups.
PG&E is proposing to change the transmission-level eligibility standard from a two-part standard to a single standard. Under the proposed single standard criteria, a distribution-level noncore customer will receive transportation service under transmission-level rate during any month when their historical 12-month usage is 3 million therms or higher. PG&E contends that the single standard will simplify the administration and monitoring of the eligibility, and allow eligible customers to pay transmission-level rates when they first become eligible, rather than waiting for the annual review of eligibility under the two part standard. PG&E also states that this proposal will not result in any cost shifts or rate impacts.
No one opposes PG&E's proposal to modify the transmission-level eligibility criteria. The proposal to use the single standard of eligibility for transmission-level rates is adopted.
PG&E has proposed 100% balancing account treatment for its noncore distribution revenues. Under the Gas Accord, noncore distribution revenues are subject to throughput risk. PG&E's proposal, if adopted, would eliminate this risk.
Duke points out that SoCalGas received balancing account protection on an interim basis only, due to a delay in the processing of its BCAP. Duke also points out that the Commission stated that the 100% balancing treatment shall not set a precedent. (D.02-12-017, p. 9.)
PG&E proposes that it be given 100% balancing account protection for its noncore distribution revenues. Under the Gas Accord, balancing account treatment for these revenues was eliminated. (73 CPUC2d 825.)
PG&E is raising the balancing account issue in this proceeding, rather than in the BCAP, because it seeks to reestablish what was in place before the Gas Accord. PG&E also points out that in D.02-12-017, SoCalGas received 100% balancing account protection.
The issue of balancing account treatment for PG&E's noncore distribution revenues should be raised in PG&E's next BCAP filing. The BCAP is the proceeding in which the forecasted throughput that PG&E complains of, was calculated. We also note that SoCalGas' request for balancing account treatment was raised in its BCAP proceeding, and that the balancing account protection was only for an interim period.
Although the Gas Accord eliminated the balancing account treatment for PG&E's noncore distribution revenues, those distribution costs, revenues and throughput are addressed in the BCAP, which PG&E acknowledges. Any balancing account protection for distribution revenues should be addressed in the proceeding where those issues originate from. Accordingly, the proposal to adopt 100% balancing account protection for PG&E's noncore distribution revenues is not adopted.
PG&E proposes to create a single electricity generation class consisting of noncore merchant electric generators, PG&E's retained gas-fired power plants, cogeneration facilities, and solar electric generation load. The class would be segmented into distribution and transmission-level rates, with distribution-level customers using more than 3 million therms per year qualifying for the transmission-level rate. PG&E also proposes to eliminate the cogeneration gas allowance (CGA) and instead implement anti-gaming measures to ensure that only gas used for electric generation qualifies for electric generation gas rates. PG&E also proposes to eliminate the collateral discount rule (CDR), which requires that any discount offered to a non-cogenerator electric generator also be offered to cogenerators.
CCC/Calpine, along with Mirant, support the creation of a single electric generation class. The implementation of a single-EG class will close the gap between the electric generation rate design of PG&E and the Sempra gas utilities, which already has a single electric generation class. In the SoCalGas BCAP, the Commission adopted many of the changes that PG&E proposes here, including segmentation of the electric generation class, and the elimination of the CGA and the CDR.
CCC/Calpine have two concerns regarding PG&E's single electric generation class proposal. First, PG&E's proposal that all electric generation customers bear 75% of the distribution costs that otherwise would be allocated entirely to distribution-level customers should be revised to allocate 100% of the distribution costs to distribution-level electric generation customers. Second, PG&E's proposed anti-gaming rules associated with the elimination of the CGA are unduly harsh and defeat the purpose of eliminating the CGA. In particular, PG&E should be required to use a customer-specific heat rate instead of a generic heat rate to calculate a cogeneration customers' electric generation gas usage.
PG&E's proposal that distribution-level electric generators should only bear 25% of the historical subsidy by transmission-level electric generators, is a compromise that does not adequately address a customers' actual cost of service and seeks to perpetuate inappropriate cross subsidies. PG&E basically admits this when it proposes to maintain 75% of the distribution-level subsidy in order to manage rate impacts to smaller distribution-level generators. PG&E's proposed distribution-level electric generation rate would only be $0.20 per Dth higher than the comparable transmission-level rate. This is only 2/3rd of the $0.30 per Dth differential that was approved by the Commission in D.00-04-060 at 53-56 for SoCalGas and SDG&E. Removing the entire subsidy for distribution-level electric generation customers would not be out of line with the differential in PG&E's existing industrial gas rates. PG&E's distribution-level industrial rate is $0.73 per Dth higher than the comparable transmission-level rate. Eliminating the subsidy of distribution-level electric generation customers would produce a transmission/distribution-level electric generation rate differential of $0.81 per Dth.
CCC/Calpine state that the elimination of the CGA is likely to benefit small, distribution-level electric generators that have relatively higher heat rates. For example, PG&E's proposed generic heat rate for cogenerators less than 5 MW is above PG&E's current CGA. Allowing all of the gas consumed by smaller electric generators to qualify for electric generation rates, which will continue to be lower than their otherwise applicable industrial rates, will reduce the smaller cogenerators' overall gas costs and mitigate at least some of the impacts associated with PG&E's rate segmentation proposal. As such, the Commission should fully implement the proposed distribution and transmission-level segmentation, as it has done for the Sempra electric generators and for PG&E's noncore industrial customers.
NCGC agrees with CCC/Calpine that the Commission should require PG&E to revise its proposal in order to require that distribution-level electric generation customers pay 100%, rather than merely 25%, of the distribution costs allocated to distribution-level electric generation service. CCC/Calpine agree with NCGC's assessment that the continued imposition of distribution-level costs on transmission-level customers, after adoption of a single, segmented electric generation rate would cause the transmission-level customers to continue to bear costs that they do not cause.
The second concern of CCC/Calpine with PG&E's single electric generation class is that PG&E proposes to employ anti-gaming rules that ensure that cogenerators only receive electric generation gas rates for gas used in electricity production, as opposed to gas used in industrial applications. CCC/Calpine contend that PG&E proposes to employ artificially high generic heat rates, as presented in Table 14-12 of Exhibit 3. CCC/Calpine assert that the Commission should reject PG&E's proposal to use generic heat rates for a number of reasons. First, it amounts to an attempt by PG&E to enforce an efficiency standard for electric generators. If implemented, PG&E's proposal would improperly regulate efficiency because generators would have to pay a higher gas transportation rate if their equipment is not as efficient as PG&E's generic heat rate. Setting such an efficiency standard is not the purpose of the anti-gaming rules. Rather, the purpose is to ensure that the electric generation gas rate applies only to gas used for electric generation.
CCC/Calpine state that the CGA, which PG&E proposes to abolish, is a mechanism that limits cogenerator's access to electric generation gas rates based upon their operational efficiency relative to other electric generators. The Commission abandoned the CGA in the SoCalGas BCAP because cogenerators and other electricity generators are now competing, and a mechanism such as the CGA is neither necessary to promote economic efficiency nor desirable, as it would put cogenerators at a competitive disadvantage vis-a-vis other generators. CCC/Calpine contend that it makes no sense to eliminate the CGA, only to replace it with a new mechanism that regulates the efficiency of cogenerators, which CCC/Calpine contend is actually more restrictive than the CGA. While PG&E's current CGA is 10,681 BTU/kWh, PG&E would cut off access to the electric generation gas rate at 9,000 BTU/kWh using PG&E's proposed generic heat rates for cogenerators of 10 MW or greater. Such a proposal cannot be accepted.
CCC/Calpine also state that PG&E's proposal on the heat rate does not accomplish the goal of deterring potential gaming. PG&E's witness agreed on cross examination that cogenerators with a heat rate lower than PG&E's generic heat rate can obtain electric generation rates for gas that is used for industrial purposes. (9 RT 972) Also, PG&E's heat rate proposal will improperly assess industrial rates to gas that is used to generate electricity by cogenerators whose heat rates are higher than the applicable generic heat rate. (See 9 RT 968.)
PG&E's witness also acknowledged that the anti-gaming mechanism should not deprive cogenerators of electric generation rates for gas used in the cogeneration of electricity, stating that "in the event of a customer that thought that 100 percent of his gas was not qualifying, PG&E would certainly be willing to entertain a customer-specific heat rate for purposes of measuring gas usage." (9 RT 972.)
CCC/Calpine contend that the Commission should simply extend the Sempra anti-gaming mechanism to PG&E and require PG&E to employ customer specific heat rates. There is no reason to require cogenerators to make a showing to PG&E in order for PG&E to agree to use customer-specific heat rates.
CCC/Calpine assert that the arguments of RealEnergy, Inc. (RealEnergy) and DGS are not valid criticisms. First, CCC/Calpine point out that these two parties did not participate in the hearings, and presented no evidence demonstrating that distributed generation would either be discouraged or rendered uneconomic as a result of the proposal to institute a single electric generation. Second, while encouraging distributed generation is a laudable goal, the Commission should not use hidden subsidies in gas rates, paid by other electricity generators, in order to achieve this goal. Rather, programs to encourage distributed generation should be purposefully developed, while ensuring that the cost of any such program is of an appropriate magnitude, and is levied against appropriate parties.
DGS opposes PG&E's proposal to make changes to the electric generation class. The proposed changes would include eliminating electric generation parity for smaller cogeneration facilities, and transferring substantial costs from variable to fixed rates.
With respect to cogeneration parity, DGS points out that Commission policy has been to allow generators to compete on the basis of efficiency and not on artificial rate differentials. PG&E's proposal would essentially eliminate the right of smaller distributed generation to obtain the same gas transportation rates afforded to larger generators. DGS recommends that electric generators, regardless of size, pay the same basic rate.
PG&E proposes several changes to the design of its electric generation rates to align its rate design structure with changes resulting from electric industry restructuring, and with SoCalGas' and SDG&E's electric generation rate structure.
NCGC supports the changes that PG&E proposes. NCGC contends that the segmented electric generation rates will provide a more accurate price signal for potential generation projects that are considering locating in PG&E service territory.
NCGC contends that PG&E's proposal for a single, segmented electric generation class is consistent with the single, segmented electric generation class on the SoCalGas and SDG&E systems, which was adopted in D.00-04-060. Since D.00-04-060 found that the segmented transportation rate for SoCalGas and SDG&E complied with the cogeneration parity requirements of § 454.4, PG&E's proposal should comply as well.
NCGC also supports the elimination of the CGA and supports the adoption of anti-gaming measures, primarily the requirement that there be a separate PG&E meter to measure gas use at electric generation facilities. NCGC also supports elimination of the CDR, since parity is achieved through the single, segmented electric generation rate.
PG&E proposes that for 2004, distribution-level electric generation customers be required to pay a distribution rate component that reflects only 25% of the distribution costs allocated to distribution-level electric generation service. Under PG&E's proposal, the remaining 75% of the distribution costs allocated to the distribution-level electric generation customers would be spread equally to all transmission and distribution-level electric generation customer volumes.
NCGC is opposed to the phase-in of distribution-level costs. Such a phase-in is inconsistent with what occurred on the SoCalGas and SDG&E systems, where there was no phase-in provision. NCGC believes that the same should be done here. NCGC contends that transmission-level customers do not cause PG&E to incur distribution-level costs. Continuing to impose distribution-level costs on transmission-level customers after the adoption of a single, segmented electric generation rate would be unfair to transmission-level customers to bear costs that they do not cause.
Although PG&E claims that a phase-in would manage the rate impact of segmentation on smaller distribution-level generators, NCGC contends that PG&E has not provided any evidence that the rate impact of full rate segmentation on distribution-level generators would be unmanageable for those generators. PG&E's proposal to phase-in electric generation rate segmentation should be rejected.
RealEnergy is a provider of small-scale distributed generation projects.
PG&E proposes the creation of a single electric generation class, with the class segmented by transmission and distribution service levels. Customers who use 3 million therms or greater would be considered transmission-level. Under PG&E's proposal, RealEnergy's facilities would be considered distribution-level.
Currently, the distribution costs allocated to distribution-level electric generation customers are spread equally to all transmission and distribution-level electric generation customers. Under PG&E's proposal, distribution-level electric generation customers would pay a distribution rate component based on 25% of the distribution costs allocated to distribution-level electric generation and cogeneration customers. The remaining 75% of the distribution costs allocated to distribution-level customers would continue to be spread equally to all transmission- and distribution-level electric generation customer volumes through the distribution rate component.
RealEnergy favors keeping the current rate structure. RealEnergy points out that the cost of the gas resource can make or break a small on-site generation project. The adoption of a rate structure that renders a project uneconomic would be counter to the benefit such a structure would provide. The Commission should avoid imposing massive rate shock on individual customer classes without serious cause or efforts to mitigate such impacts.
If the Commission decides not to retain the current rate structure, then RealEnergy supports PG&E's proposal for the 25%/75% apportionment. PG&E's proposal would at least try to mitigate the rate shock such customers would feel if PG&E's single electric generation class were fully implemented. RealEnergy contends that the opposition of CCC/Calpine and NCGC to PG&E's 25%/75% phase-in does not consider the important public policies for fostering distributed generation.
PG&E proposes to establish a single, electric generation class which includes all noncore electric generation, qualifying cogeneration, and solar electric generation load. This proposal is in response to the February 26, 2002 scoping memo, and finding of fact 10 in D.01-11-001.
PG&E proposes to create a single electricity generation class consisting of noncore merchant electric generators, PG&E's retained gas-fired power plants, cogeneration facilities, and solar electric generation load. Under PG&E's proposal, electric generation customers would be segmented into distribution level or transmission-level customers. For transmission-level service, there would be four tiers based on the number of therms used per year. The transportation charges for both service levels would be based on volume. (See Ex. 3, Table 14.1-2.)
PG&E's proposal was made in response to the scoping memo, which asked if segmenting of PG&E's electric generation rates should be addressed in this proceeding. (Scoping Memo, p. 6.) NCGC had raised the segmentation issue in PG&E's 2001 BCAP, and as part of the settlement adopted in that proceeding, the parties agreed to defer the segmentation issue to the Gas Accord II settlement discussions. (See D.01-11-001, FOF 10.F.4).)
DGS opposes PG&E's proposal because the new Schedule G-EG will prevent smaller distributed generation facilities from obtaining the same gas transportation rates.94 DGS believes that this will discourage the development of such facilities.
In deciding whether PG&E's single electric generation rate should be adopted, we first consider DGS' opposition to the proposal. DGS' argument that distributed generation facilities will be prevented from obtaining favorable gas transportation rates is undercut by RealEnergy's statement in its opening brief that its distributed generation facilities would fall under distribution-level service. Furthermore, DGS did not present or cite any evidence in the record about what the consequences might be for distributed generation if the single electric generation class proposal is adopted. Although the cutoff of 250,000 therms may prevent new projects from qualifying for the electric generation rates, DGS has not demonstrated why PG&E's proposal should not be adopted.
In D.00-04-060, we adopted a single electric generation customer class for the two Sempra utilities, SoCalGas and SDG&E. The electric generation rate for SoCalGas and SDG&E was segmented by throughput level. The CDR and the CGA were eliminated. The decision also concluded that the single electric generation customer class for the Sempra utilities complied with § 454.4. (D.00-04-060, pp. 54-55, 154.)
PG&E's proposal for a single electric generation customer class is similar to what was adopted in D.00-04-060, including the elimination of the CDR and CGA. There are two notable differences between PG&E's proposal and the one that was adopted for the Sempra utilities. First, the segments for Sempra are divided by throughput levels, either above or below three million therms. The PG&E proposal segments by dividing the class into distribution and transmission service levels, and then the transmission service level is divided into four tiers based on usage.
Although the segments differ between PG&E's proposal, and what we approved in D.00-04-060, the segments are still based on throughput and service level. PG&E's proposal for a single electric generation customer class, like the one adopted for the Sempra utilities, treats electric generators alike, and therefore grants parity to cogenerators. We conclude that PG&E's proposal complies with § 454.4.
The second difference between PG&E's proposal and what was adopted for SoCalGas is the anti-gaming measure. Since the CGA is eliminated, the purpose of the anti-gaming measure is to ensure that the gas qualifying for the electric generation rate is being used to generate electricity. If no metering is available to measure gas usage at the electric generation facility, PG&E proposes that the gas volumes be measured "using other gas metering devices and by the recorded net electric generation's output in kilowatt hours (kWh) multiplied by the average heat rate for similarly sized EG facilities, as classified in Table 14-12." (Ex. 3, p. 14-38.)
The SoCalGas tariff provides that the customer will be billed the lesser of total metered throughput, or "an amount of gas equal to the customer's recorded power production in kilowatt-hours (KWH) times the average heat rate for their electric generation facilities." The tariff also provides that when required, the "electric generation customers will provide the utility with the average heat rate for electric generation equipment as supported by documentation from the manufacturer." If that is not available, the "operating data shall be used to determine customer's average heat rate." (SoCalGas, Schedule GT-F, Special Conditions 19, 20; See Ex. 6, p. 48, Att. RTB-4.)
CCC/Calpine disagrees with PG&E's proposal to use the average heat rate for similarly sized facilities as shown in Table 14-12 of Exhibit 3. PG&E did not respond to the CCC/Calpine suggestion to use the same rules that SoCalGas uses in its Schedule GT-F tariff. (See Ex. 6, p. 48.)
We have compared the method proposed by PG&E, and the method that SoCalGas has been authorized to use. The methods are very similar in that a meter must be used unless it is not economically feasible to do so. The methods differ though when it comes to measuring gas usage if no metering is available. We agree with CCC/Calpine that PG&E's use of an average heat rate for similarly sized electric generation facilities may not correctly reflect the customer's actual heat rate. Instead of PG&E's proposed method of measuring usage, the method set forth in SoCalGas' Schedule GT-F tariff in Special Conditions 19 through 22 shall be used.
RealEnergy and CCC/Calpine disagree with how the distribution costs that are allocated to distribution-level electric generation customers should be paid. PG&E proposes that to mitigate rate shock to distribution-level electric generation customers, that they be allocated 25% of the costs, and the remaining 75% be spread equally to all transmission and distribution-level electric generation customer volumes through the distribution rate component.
RealEnergy favors the existing allocation of spreading these costs equally to all transmission and distribution-level electric generation customers. In the event the existing allocation is not retained, RealEnergy favors PG&E's 25%/75% proposal.
CCC/Calpine and NCGC believe that distribution-level electric generation customers should pay 100% of the distribution costs that are allocated to them, instead of transmission-level electric generation customers having to subsidize part of the remaining 75% of the distribution-level electric generation customers' distribution costs. The testimony of the CCC/Calpine witness points out that the differential between PG&E's distribution-level industrial rate is $0.73 per Dth higher than PG&E's comparable transmission-level rate. If the subsidy of distribution-level electric generation customers was eliminated, the differential between PG&E's electric generation distribution-level and transmission-level would be $0.81 per Dth.
We have considered the financial impact on both distribution-level and transmission-level electric generation customers. Although we are sympathetic to the transmission-level electric generation customers' concern, PG&E's method will ease the rate shock on these distribution-level customers. We will adopt PG&E's proposed 25%/75% method for recovering the distribution costs that are allocated to distribution-level electric generation customers for 2004. The distribution-level electric customers should be prepared, however, to take 100% responsibility in 2005 for the distribution costs that are allocated to them.
PG&E's proposal for a single electric generation customer class, as described at pages 14-36 to 14-39 of Exhibit 3, and as revised by our discussion above, is adopted.
84 One of PG&E's arguments regarding the roll-in of Line 401 is if an alternate pipeline had been built, it is unlikely that as much capacity as Line 401 would have been built because "there was a considerable amount of slack capacity on PG&E's system until mid-2000...." (Ex. 4, p. 3-9.) This statement about slack capacity supports TURN's argument that PG&E faced the risk that the Line 401 would be underutilized, which in turn supports the use of TURN's load factor adjustment to Line 401.85 The effect of PG&E's local transmission proposal on core wholesale customers was mentioned briefly in Chapter 14 of PG&E's application, where it stated in part that "the core retail local transmission rate will also apply to core wholesale customers because they are provided the same level of reliability." (Ex. 3, p. 14-22.) 86 According to PG&E's Rule 1, Palo Alto's wholesale load is classified as a noncore customer, and not as a core customer. Palo Alto points out that under PG&E's definition of a core customer, the core customer must be physically connected to the local distribution system. None of Palo Alto's core loads are physically connected to PG&E's local distribution system. 87 Palo Alto points out that in PG&E's 1995 BCAP decision, D.95-12-053, and SoCalGas's 2000 BCAP decision, D.00-04-060, the gas transportation rates and revenue requirements for wholesale core customers were not included as part of core rates and revenues. Instead, wholesale core customers' rates and revenues are reflected in noncore rates and revenues. (Ex. 54.) 88 As a wholesale customer, Palo Alto is required to execute a Natural Gas Service Agreement (NGSA). Core customers do not execute an NGSA. Wholesale customers are also required to have meters which are capable of measuring flow on a daily basis. PG&E's core customers are not required to have daily metering. PG&E's Core Procurement Department, and core transport groups, must balance to a forecasted usage. Palo Alto and other wholesale customers do not have to balance to forecasted usage. 89 Palo Alto asserts that PG&E's subsidy argument is wrong. As PG&E acknowledged, in the Gas Accord and continuing in 2003, wholesale customers have paid the local transmission rate for the noncore class and contributed to the revenue requirement for the noncore class. (Ex. 3, p. 14-22; Ex. 4, p. 14-14; RT 1114-1115.) In order for retail core customers to have subsidized wholesale customers, revenue would have to shift from Palo Alto and Coalinga, the only wholesale customers when the Gas Accord was adopted. Exhibits 54 and 55 clearly demonstrate that there was no shifting of local transmission revenue from wholesale or other noncore customers to retail core customers. 90 Palo Alto points out that there are major cost differences between retail core customers and wholesale customers. The average throughput per wholesale customer is much greater than the average retail core throughput per customer. In addition, many of PG&E's retail core customers are connected to distribution feeder mains (DFMs), which are part of PG&E's local transmission system. Wholesale customers, such as Palo Alto, are served by local transmission pipelines that are connected to PG&E's backbone transmission system and no DFMs are required to serve them. (Ex. 1, pp. 2-5; 7 RT 763.) Palo Alto also receives gas at a much higher pressure than retail core customers. Also, the balancing requirements for noncore customers, including wholesale customers, is much stricter than the balancing requirement for core procurement. 91 CCC/Calpine disagree with PG&E's estimate of how much load will be a backbone-only rate. CCC/Calpine estimate that, at most, 199 MDth/d of load might directly connect to the backbone. 92 Although some of this cost shift might be recovered from a stranded cost charge imposed on customers who migrate to a backbone-only rate, none of the parties have developed concrete suggestions for determining how much such a charge should be. 93 PG&E's proposal for a single electric generation class would allocate distribution costs equally to all cogeneration and electric generation end-users. 94 In DGS' opening brief, DGS takes issue with the customer access charge shown in Table 14.1-12 of Exhibit 3. DGS, however, did not present any witnesses or ask any questions of the available witnesses about the development of the customer access charges. The customer access charges, and the expenses which feed into the charges, has been addressed earlier.