Word Document PDF Document

PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

ENERGY DIVISION RESOLUTION E-3831

RESOLUTION

Resolution E-3831. Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas and Electric Company (SDG&E) filed tariffs in compliance with Ordering Paragraph (OP) 17 of Decision (D.) 03-04-030 to implement the Departing Load Customer Generation Cost Responsibility Surcharge (CG CRS) Effective on Filing Subject to Post-Filing Review by the Energy Division. These Advice Letters are approved with modifications.

By PG&E Advice Letter AL 2375-E Filed on April 17, 2003, Supplemental AL 2375-E-A Filed on May 5, 2003; SCE AL 1700-E Filed on April 17, 2003; and SDG&E AL 1488-E Filed on April 17, 2003.

__________________________________________________________

SUMMARY

PG&E, SCE, and SDG&E propose a Cost Responsibility Surcharge for Customer Generation.

This Resolution implements the customer generation departing load1 cost responsibility surcharge (CG CRS) pursuant to Decision (D.) 03-04-030 (the CG CRS Decision), as modified2 by D.03-04-041. The CG CRS tariffs as modified herein are effective as of the filing date, subject to Energy Division's review and approval.

BACKGROUND

The 2000-01 crisis necessitated that Cost Responsibility Surcharges apply to Customer Generation.

In D.02-03-055, we confirmed that direct access (DA) was suspended effective after September 20, 2001 but determined that bundled service customers should not be burdened with additional costs as a result of the significant migration of load to DA from utility bundled service that occurred between July and September of that year. Thus we initiated the Rulemaking 02-01-011 to develop a Cost Responsibility Surcharge (CRS) to mitigate this cost shifting potential. The extraordinary energy prices during the 2000-01 crisis also created an incentive for departing load (DL) other than DA to migrate away from bundled utility service. Thus, the administrative law judge (ALJ) by ruling dated March 29, 2002, directed that a CRS applicable to DL also be developed.

The Customer Generation Cost Responsibility Surcharge is based on the principles developed for the Direct Access Cost Responsibility Surcharge.

By D.03-04-030, we adopted policies and mechanisms to implement a CRS applicable to customers of PG&E, SCE, and SDG&E that self-generate to meet all or part of their load. The CRS comprises four separate charges, all capped presently at 2.7 cents per kWh.3 The component charges in the order of recovery under the cap consist of:

We now implement CG CRS tariffs.

We now implement CG CRS tariffs for the utilities. The California Energy Commission (CEC) has developed its process to certify systems as eligible for exceptions and track projects under the caps that we adopted for CRS exceptions. As of early March of this year, the CEC's Megawatt Cap web page5 is officially operational, and the utilities are accepting applications for CG CRS exceptions.

NOTICE

Utility Advice Letters were noticed in the Commission's Daily Calendar and served on interested parties.

Notice of PG&E's AL 2375-E, SCE's AL 1700-E, and SDG&E's AL 1488-E was made by publication in the Commission's Daily Calendar. PG&E, SCE, and SDG&E state that, in accordance with Section III-G of General Order 96-A, copies of their respective ALs and Supplemental ALs have been served on interested parties including those on service lists in R.99-10-025 (PG&E) and R.02-01-011 (SCE and SDG&E).

PROTESTS

Two parties protested all three advice letters, and two parties each protested single advice letters.

Two parties, 1) the Joint Parties Interested in Distributed Generation/Distributed Energy Resources (Joint Parties) and 2) the Energy Producers and Users Coalition and the Kimberly Clark Corporation and Goodrich Aerostructures Group (EPUC) timely protested PG&E's AL 2375-E by May 7, 2003. The California Solar Energy Industries Association (CAL SEIA) submitted a late protest of PG&E's AL 2375-E on May 12. PG&E responded to the protests of the Joint Parties and EPUC on May 14 and to the protest of CAL SEIA on May 19.

The Joint Parties, EPUC, and the California Independent Petroleum Association (CIPA) timely protested SCE's AL 1700-E by May 7, 2003. SCE responded to all of these protests together on May 14.

The Joint Parties and EPUC timely protested SDG&E's AL 1488-E by May 7, 2003. SDG&E responded to each of these protests separately on May 14, 2003.

The following is a summary of the major issues raised in the protests.

DISCUSSION

Tariff names should include "Customer Generation, CG" and contain the definitions and rates adopted in D.03-04-030.

In the decision that authorized the filings addressed herein, we adopted policies and mechanisms to apply CRS to DL served by CG. Therefore, this resolution specifically addresses CG CRS implementation policies and mechanisms. Because a variety of terms are used interchangeably with "customer generation," for clarity, we will direct that utility tariffs adopted herein include the term, "Customer Generation, CG" in their titles.

Correct date references and remove expired rates.

EPUC and the Joint Parties object to the definition PG&E proposes for Customer Generation Departing Load in Special Condition (SC) 1.b.3, as not entirely conformed to the definition provided in D.03-04-040. The phrase "remains physically located at the same location within PG&E's service area as it existed on December 20, 1995" does not match the language used in the CG CRS Decision, which states "remains physically located at the same location or elsewhere within the utility's service territory as of the date on which this Commission decision becomes effective" (at p. 2).

PG&E in its response explains that it proposes to simplify its tariffs relating to CG Dl by combining elements of Electric Preliminary statement Section BB and the currently expired Schedules E-DEPART and E-EXEMPT into one rate schedule. In this way, PG&E argues that customer-generators will be able to refer to a single tariff containing information on all nonbypassable charge obligations. D.03-04-030 did not authorize the utilities to re-introduce any expired rates or rate schedules. It merely authorized CG CRS implementation. Therefore, the utilities should address any possibly erroneously expired rates in other appropriate forums.6 The "service territory" limitation within the definition of CG DL should be as the CG CRS decision specifies, as requested by the Joint Parties and EPUC. SCE and SDG&E agree with the Joint Parties to reference April 3, 2003, the date the Decision became effective, in the definition of CGDL. Also SCE agrees with the request of the Joint Parties and EPUC, consistent with OP 4, that SCE change the proposed applicability date of the tariff modifications from January 17, 2001 to February 1, 2001. Thus SCE will change the dates in its Preliminary Statement Section W.1.b, W.1.c, W.2, W.5.c, and Schedule DL-CRS, Applicability and Rates sections and SC 3.

Specify excluded load reductions.

The Joint Parties and EPUC protest that SDG&E should expand Schedule DL-CRS to explicitly state the types of DL that are specifically excluded from CG CRS, as set forth on page 3 of D.03-04-030.

Utility CG CRS tariffs should include the explicit exclusion language from the decision, as cited above, indicating the types of load reductions to which CG CRS do not apply: for example, changes in usage occurring in the normal course of business, load met by CG not requiring utility wires, and load temporarily taking service from a back-up generation unit during emergency conditions. The language in SCE's proposed Preliminary Statement Part W, section 1.c and PG&E's proposed Schedule E-DCG, SC 1.b complies. SDG&E shall modify its tariffs accordingly.

Add load management program exclusion.

Consistent with the principal in the CG CRS decision that back-up generation operated during grid outages is excluded from the definition of CG, PG&E argues that CG operation as part of a Commission- or ISO-sponsored load management program should be treated as any other load reduction that does not displace usage that would have been supplied by the utility. Therefore, PG&E has drafted tariff language assuming that operation of a CG unit in response to curtailment requests be treated similarly as operation of the unit during a grid outage, since in neither case does the operation displace usage delivered by PG&E. The Joint Parties in their Protest support PG&E's proposal.

The proposed language is in keeping with the principle in the CG CRS Decision identifying CG as generation that replaces the utility or DA purchases (at pp 2-3) and not the subject of any protest. Therefore, we direct each utility to add this additional CG exclusion for dispatchable backup generation used in connection with the dispatch of a load management program sponsored by the Commission, California Energy Commission or California Independent System Operator, or any other successor operator.

Include reference to "physical test" in the Customer Generation Cost

Responsibility Surcharge tariffs.

The Joint Parties and EPUC further recommend that SDG&E's tariffs specifically describe the "physical test" necessary to administer exclusion of new customer load or incremental load of an existing customer, as described in footnote 61 of D.03-04-030. The Joint Parties and EPUC agree that SDG&E should use the tariff language proposed by SCE. SDG&E in response agrees to add this proposed change.

PG&E in its AL states that the ordering paragraphs are silent on whether new or incremental load served by customer generation that meets the "physical test" specified by D.98-12-067, is exempt from all departing load charges or just CTC. However, the decision does conclude (COL 14) that this same physical test would be used to determine that CG load is not obligated to pay a CRS. PG&E's tariff language assumes the Commission's intent is to exempt from all DL charges, any new or incremental load served by an on-site or over-the-fence generator that can pass the "physical test." PG&E's interpretation is correct, and each of the utilities should reference the "Physical Test" adopted in D.98-12-067 in their CG CRS tariffs.

"Tenant's" should be "Tenants."

Finally, the Joint Parties note a minor correction needed in SCE's Preliminary Statement Section W.1.b. The word "tenant" in line 7 and SC 2 of Schedule DL-CRS should be changed to "tenants," consistent with D.03-04-030 at p. 4. SCE in its response takes the position that this change is not supported by the text of the Decision and should not be made. SCE accurately points out that the decision at p. 4 actually states "tenant's" as in the possessive form, not as in the plural form "tenants." From the context, this is clearly a typographical error, since the possessive form would not be consistent in concept with "affiliates" in the same sentence. Therefore, SCE, as well as SDG&E, should make the correction as noted.

Utilities' measurement provisions for billing Competition Transition Charges shall apply for billing Cost Responsibility surcharges.

EPUC objects to the requirement PG&E added to its tariffs to measure CG load by means of "suitable standard electric meters installed and owned by PG&E, except where, in the opinion of PG&E, the installation of a meter is impractical. Where installation of a meter is impractical, the amount of Customer Generation Departing Load shall be estimated by PG&E in a manner to be approved by the Commission's Energy Division." (Schedule E-DCG, SC 5). EPUC cites PG&E's and SCE's tariffs measuring Departing Load for purposes of billing the CTC from PG&E's Preliminary Statement BB, §2b and SCE's Preliminary Statement Part W, Section 3. EPUC states that these measurement systems have worked since the implementation of the CTC, and no reason has been advanced in this proceeding why existing tariffs should be modified. Moreover, this change was not discussed in D.03-04-030.

In response, PG&E argues that its current tariff was written for situations where a customer departs entirely from PG&E's system to take service from another provider, such as a municipal utility or irrigation district. Therefore, PG&E's current tariff provision regarding third party metering for departed customers is not readily transferable to situations involving Customer Generation Departing Load. Also, PG&E maintains that an estimate of generator output based on the customer's historical load is not practical for situations where only a portion of the customer's load departs. Thus, PG&E concludes that the most accurate and simplest way to bill CG charges is through the use of utility-installed, owned, and maintained meters to measure generator output data. PG&E also suggests the alternative, whereby PG&E could submit estimated capacity factors for different types of distributed generation (perhaps based on manufacturers' promotional materials), and allow customers that believe they are disadvantaged by the estimates to request customer-financed but PG&E-installed, maintained, and read meters. PG&E would ask the Commission to approve these estimates in advance.

EPUC correctly noted that D.03-04-030 is silent on the means for obtaining billing determinants, which suggests that existing provisions are sufficient. Utility tariffs have provisions for third party metering, as well as for load estimation for use in billing the CTC. These provisions are similarly workable for billing the CG CRS, as proposed by SCE and SDG&E. PG&E's argument about the lack of applicability to partial load departure is not convincing, as existing tariffs are also workable for such instances. Therefore, we reject PG&E's new provision for measuring CG load and instead direct that existing Utilities' Tariff Provisions for Measuring CTC be Applied to CG.

Delete PG&E's Application Form for Net Metering Customers.

CAL SEIA protests PG&E's proposal to require Net Metering customers to file the 7-page form 79-1001 denoting the charges from which they should be exempted, given the details of their system. CAL SEIA reasons that for all photovoltaic (PV) systems up to 1 MW, the information is always the same; these systems are exempt from all charges except the PPP charge. According to CAL SEIA, most PV system owners are homeowners with systems in the 2 to 4 kW size. System purchasers must already notify PG&E that they are requesting interconnection and net metering. In CAL SEIA's view, PG&E provides no compelling reason, given the state-endorsed objective of encouraging the purchase and installation of net metering systems, that demonstrates why these customers should make a declaration of their departing load and fill out a seven-page form restating the information already contained in other documents they must file with PG&E.

PG&E in its response to CAL SEIA agrees that completion of Form Number 79-1001 requests some information that is unnecessary for non-cogeneration installations. Given CAL SEIA's comments, PG&E in its response agreed to revise Form 79-1001 to clarify what information is required only of non-cogeneration installations. Alternatively, PG&E could file a new significantly shorter form that would apply solely to non-cogeneration technologies. PG&E believes that the filed form 79-1001 should be used for all applications until workshops are completed.

Rather than holding workshops, we resolve all issues as set forth herein. PG&E's Form Number 79-1001 is unnecessary and shall not be required for net metering customers.

Net Metering customers pay Public Purpose Program charges on net consumption.

CAL SEIA protests PG&E's proposal in Schedule E-DCG, section 2(d) to collect "minuscule amounts of Public Purpose Program (PPP) charges" from net metering PV generating systems up to 1 MW installed after September 30, 2002 [2003 in tariff and in AB 58]. CAL SEIA further presumes PG&E is proposing to charge customers for the expense of installing a separate meter to measure the output of their PV systems. PG&E in its response to CAL SEIA states that for residential PV generation, PG&E will likely determine that installation of a meter is impractical and instead estimate generator output according to a method to be developed with Energy Division approval.

PU Code Section 2827 (k) requires that net metering and co-metering customers shall not be exempt from the public benefits charge. Therefore, we cannot support CAL SEIA's conclusion that the very nature of the proposed attempt to collect PPP charges on PV systems is inconsistent with other state policies clearly intended to encourage and promote the public's purchase and installation of such systems. In Resolution E-3847, we determined that net metering customers would pay PPP charges on their net consumption. By this means, net metering customers are not likely to bypass PPP charges, since the net metering program does not reward net generators.

Caps apply to ultra-clean Customer Generation sized over 1 MW and other Customer Generation categories.

Based on several protests and responses on this subject, considerable confusion exists as to which types of CG are constrained by the caps adopted in OP 10. In the CG Decision, we adopted certain CRS exceptions for particular CG types, only some of which are to be limited by caps defined in OP 10. Grandfathered CG includes those that departed prior to Feb 1, 2001 (OP 4) and those that met the California Environmental Quality Act (CEQA) requirements and subsequently departed by certain dates (OP 5). We also provided exceptions for Biogas digester customer generation (OP 6) and for CG systems sized up to 1 MW that are eligible for either net metering or a CEC/CPUC program (OP 7). Exceptions identified in OPs 4 through 7 are not subject to the OP 10 cap. The cap applies to the CG identified in OP 8 (systems over 1 MW but ultra-clean) and OP 9 (CG Other than that defined in OPs 4-8) with more restrictive caps set for the latter category.

Customer Generation Exceptions Table

OP

CG Type

Exception

4

Departed prior to Feb 1, 2001

DWR Bond and Power Charges

5

Met certain CEQA and departure deadlines

DWR Power Charge

6

Biogas digesters

All CRS

7

Systems sized up to 1 MW that are eligible for either net metering7 or a CEC/CPUC program

All CRS

8

Systems sized over 1 MW but ultra- clean

DWR Power Charge and HPC

9

CG other than that defined in Ops 4-7

DWR Power Charge

Thus, EPUC and the Joint Parties correctly note in their protest to SDG&E's AL that "grandfathered" departing load should not be counted towards the MW caps. SDG&E, in its response, concurs with this observation and suggests the following modifications to SC 3.f:

We reiterate that none of the exceptions granted in OPs 4 through 7 should be included in any of the adopted caps. SDG&E should modify its tariff language accordingly. We also note that SDG&E should add the language from OP 4 that is omitted from SDG&E's SC 3.a, the phrase, "except during any period."

With regard to grandfathered CG, EPUC and the Joint Parties also note that SDG&E did not update its tariff to reflect the technical correction of the dates in OP 5 by D.03-04-041. SDG&E in its response notes the omission and proposes language to Schedule DL-CRS that now complies. SDG&E's proposed tariff language is approved.

EPUC and the Joint Parties also suggest that SCE's proposed SC 4.d and SC 4.g and SDG&E's Schedule DL-CRS be modified to clarify that once the MW caps adopted by D.03-04-030 are met, it is the availability of new exemptions, rather than previously granted exemptions, that expire at that time. SCE states in its response that additional clarifying language is not needed. SDG&E, on the other hand, responds with suggested modifications to its proposed SC 3.f and SC 3.g clarifying that the exemptions expire for new CG departing load installed after the adopted caps are met. While SDG&E's suggested language requires modification as discussed above, the clarification SDG&E suggests regarding this aspect is appropriate. PG&E's proposed tariffs could benefit from similar clarifying language. Therefore, we direct PG&E, SCE, and SDG&E to add clarifying language similar to that proposed by SDG&E in its response. Utility tariffs specifying the caps on CG CRS exceptions should state that these exceptions expire for CG installed after the caps are met; exceptions granted before the caps were met do not expire.

Cost Responsibility Surcharge exceptions for Customer Generation sized up to 1 MW are tied to program eligibility and include Historical Procurement Charges.

The 1 MW size threshold stands.

The Joint Parties recommend SDG&E modify its proposed SC 3.d of Schedule DL-CRS and that SCE modify its proposed Section W.4.a to make it consistent with the CPUC's Self-Generation Incentive Program so that the first MW of a project up to 1.5 MW is exempt from CRS. In support of its position, the Joint Parties cite the policy discussion in the Decision (at p. 45) that explained regarding systems eligible for the Self-Generation Incentive Program, "The offering of a financial incentive clearly indicates a policy preference designed to encourage the installation of such systems. We intend to continue offering these types of systems a preference in order to encourage their installation." The Joint Parties believe that setting the requirements for eligibility for this category of CRS exemptions at the same size limit as the CPUC Self-Generation Incentive Program on which the exemptions are based would be entirely logical and reasonable.

PG&E in its AL states that the CG decision is unclear whether DG units between 1.0 and 1.5 MW, that are eligible for the CPUC's Self-Generation Incentive Program, are to receive exemptions as defined in D.03-04-030 for just the portion of their departed load usage associated with 1 MW or for none of it. PG&E has filed tariffs reflecting its interpretation that the Commission intended to allow the pro-rating of exemptions.

SCE and SDG&E reject PG&E's interpretation. SCE argues in its response on this point that the Decision specifically limits the exemption from all CRS components only to CG systems sized under 1 MW. SCE cites the body of the Decision in the last sentence of footnote 70, in Conclusion of Law 7 and Ordering Paragraph 7. These portions of the Decision provide that to gain an exemption from all CRS components, a system must be sized under 1 MW and be eligible for participation in either a CPUC or CEC self-generation incentive program. The Decision provides no indication that this exemption should apply to the CG DL of up to 1 MW served by customer generation that is eligible for one of these programs and is between 1MW and 1.5 MW in size.

We concur with SCE's interpretation. In the CG CRS decision, we maintained the 1 MW threshold to be consistent with the net metering program but also specified our intent to revisit this threshold within three years of issuance to consider technological advances or economies of scale in CG production and sale (see discussion at p. 47 and OPs 7 and 12). We also clarified in discussing the over 1 MW category that, "As discussed in the previous section [the under 1 MW section], any system that meets these criteria and is less than 1 MW in size will not be required to pay any CRS charges. For systems over 1 MW in size, however, we believe their scale dictates that they should be responsible for a fair share of the DWR bond charges. While making exception for systems under 1 MW from bond charges will not make a recognizable difference in collection amounts, collections on larger systems will have a noticeable impact. Therefore, we will require that systems meeting the Public Utilities Code Section 353.2 criteria which are over 1 MW in size pay the DWR bond charge."

Therefore, the protest of the Joint Parties regarding the 1 MW size threshold for clean CG is denied. PG&E should modify its tariff accordingly to eliminate the partial exception granted to CG eligible for CPUC program but sized over 1 MW.

Exception for Customer Generation sized up to 1 MW is tied to program

eligibility.

The Joint Parties, CIPA, and EPUC protest that SCE in SC 4.b has mistakenly combined the various categories of clean and small customer generation that the Commission has determined to be exempt from all CRS components. The revisions suggested in this area by the Joint Parties would provide that CGDL less than 1 MW need only be eligible for the CPUC's Self-Generation Incentive Program or the CEC incentive programs and not be specifically in any other way designated as a clean system before it is exempted from all CRS components.

SCE states in its response that the Decision is ambiguous8 and inconsistent in its description of Clean Customer Generation. In fact, the relevant discussion in the Decision is entitled "Clean Customer Generation Systems Under 1 MW." Yet, in describing the eligibility criteria for this category of customer generation in Ordering Paragraph 7, SCE states that the Decision inexplicably makes no reference to the term "clean" and ties the eligibility for exemption from all CRS components for CGDL of less than 1 MW to the eligibility for the CPUC or CEC's self-generation incentive programs which cover a broad range of technologies, including some that do not qualify as "clean" generation. SCE in its response does not agree to revise its proposed tariffs, as recommended by the Joint Parties, until this ambiguity is resolved.

As recognized by SCE, OP 7 ties the eligibility for exemption from all CRS components for CG of less than 1 MW to the eligibility for the CPUC or CEC's self-generation incentive program. Therefore, SCE should modify its tariffs to conform explicitly to OP 7.

A related issue is whether the exception for projects in this category depends on program eligibility or the actual receipt of program funding. The Joint Parties in their protest to PG&E's AL recommend that PG&E clarify the exemption criterion in SC 2.d, which provides that projects must be eligible for Program financial incentives. The Joint Parties cite the language used throughout D.03-04-030, i.e. that in the discussion at p. 45, clean customer generation (under 1 MW) is eligible for CRS exemptions if it is eligible for the CPUC's Self-Generation Incentive Program; Conclusion of Law 7 refers to eligibility for CPUC Self-Generation funding; and OP 7 refers to eligibility for financial incentives from the CPUC's Self-Generation Program.

The Joint Parties point out that a project could be eligible for the CPUC's Self-Generation Program, yet not be eligible for funding or financial incentives for reasons such as Program funds may be exhausted for a particular year or a project may be fully funded by another state, regional or local entity. The Joint Parties do not believe the Commission intended for systems that otherwise meet Program eligibility criteria to be subject to CRS simply because they do not receive Program financial incentives. Thus, the Joint Parties propose that PG&E's tariff language for clean customer generation exemption be modified to clarify that systems that are eligible for the CPUC's Self-Generation Incentive Program are eligible for CRS exemptions.

PG&E in its response maintains that its proposed SC 2d is consistent with OP 7. If the Joint Parties seek to modify that language, they should file a petition to modify Decision 03-04-030; the advice letter process is an inappropriate means of seeking such modification.

We agree with the interpretation of the Joint Parties that the key is eligibility, rather than the receipt of funding. However, PG&E's tariff language is clear, as it uses the "eligible" criterion, as is the case with the language proposed by SCE and SDG&E for this provision.

Exception includes Historical Procurement Charges.

The Joint Parties maintain in their protest that D.03-04-030 provides that small clean CG departing load shall be exempt from any historical procurement charge (HPC) that may be adopted for PG&E. Thus the Joint Parties recommend PG&E modify proposed Schedule E-DCG, SC 2.d to incorporate the HPC exception granted in OP 7.9 PG&E in its response opposes the Joint Parties' proposed language regarding any HPC that may be adopted for PG&E. In support of its objection, PG&E cites D.03-04-030, footnote 3, where PG&E argues that the Commission expressly states, "PG&E and SDG&E have not proposed, nor has the Commission addressed, any definition of HPC for their service territories. Thus, imposition of any HPC in PG&E or SDG&E service territories is outside the scope of this proceeding." On this basis, PG&E concludes that the Joint Parties are inappropriate to use the advice letter process as a means of exempting certain customers from any such charge.

PG&E'S conclusion is incorrect. We provided in OP 7 that "customer generation departing load that is under 1 MW in size and eligible for financial incentives from the CPUC's self-generation program or from the CEC, are not required to pay any CRS, including ... any SCE or potential other utility historic procurement charges (HPC)...." Thus, while the imposition of any HPC in other than SCE territories was outside the scope of the proceeding, adoption of an exception for certain CG was not outside the scope of the proceeding. Therefore, we direct PG&E to revise its tariffs to reflect these exceptions from the Regulatory Asset Charge per D.04-02-062.10

Finally, EPUC proposes language to correct an omission regarding the HPC provided in the Rates Section of SCE's Schedule DL-CRS. EPUC expresses concern that the means of communicating the HPC as calculated under the tariff is not included in the tariff. SCE is not opposed to EPUC's suggested addition. Therefore, we adopt it as proposed by EPUC, except that the last sentence referencing SCE's proposed CG dispute resolution process should be stricken, as explained in the next section.

Dispute Resolution Provisions set forth in Customer Generation Tariffs are disallowed.

PG&E and SCE set forth in their proposed tariffs, a dispute resolution process to address disputes specifically involving CG tariffs (PG&E Schedule E-DCG, Section 3-E and SCE's Preliminary Statement Part W.5.e). Both utilities specify essentially the same series of steps that eventually allow a dissatisfied CG customer to timely request to pursue informal dispute resolution. The utility and the customer then seek assistance in reaching informal dispute resolution from the Commission's Energy Division or mediation of the dispute from the Commission's Administrative Law Judge Division. The respective tariff sections following these, PG&E's Section 3-f And SCE's Preliminary Statement Part W.5.f-i address how the utility will deal with a CG customer's noncompliance with applicable tariffs. We did not authorize any such provisions in D.03-04-030. The utilities provided no explanation as to why CG customers require these measures. Therefore, these provisions should be stricken.

The Bond Charge is effective as of the date filed.

EPUC seeks confirmation that CGDL will commence paying the Bond Charge component of the CRS prospectively as of the date on which the Decision becomes final and unappealable. SCE cannot find any language in the Decision that either supports or contradicts EPUC's interpretation. SCE also notes that when the Commission made the Bond Charge applicable to DA customers in D.02-11-022 on the effective date of that decision, it had already adopted the appropriate ratemaking mechanisms in the Bond Charge Decision (D. 02-10-063) to guard against claims of retroactive ratemaking when D.02-11-022 became final and unappealable. In SCE's view, no such ratemaking mechanisms are adopted in the CG CRS Decision. Therefore, SCE believes that additional direction on this issue should be provided in this resolution.

D.03-04-030 provides direction concerning the applicability of the bond charge to CG. The decision is final and unappealable. The bond charge is adopted in A.00-11-038 et al and is the same value for bundled and DA customers, as well as for CG. Therefore, the utilities should update their CG tariffs to incorporate the bond charge, as adopted in A.00-11-038 et al. and applicable to CG in the manner prescribed by D.03-04-030.

Tail Competition Transition Charges quantified in other forums are the same for Customer Generation, Direct Access, and bundled customers.

Each of the utilities is in a different situation regarding implementation of tail CTC. PG&E has recently emerged from bankruptcy. SCE has completed its 2004 ERRA Proceeding. SDG&E's rate freeze ended before the 2000-01 energy crisis. Thus we have implemented the tail CTC for the utilities in a variety of forums. However, as discussed below, the tail CTC adopted for each utility should uniformly apply to bundled, DA, and CG customers not otherwise exempt.

PG&E's Tail CTC was adopted in D.04-02-062.

EPUC and the Joint Parties protest that PG&E in its AL provides a specific value for the Tail Competition Transition Charge (CTC) for 2003 in Schedule E-DCG of $0.01127 per kWh. EPUC argues that D.03-04-030 prescribed a methodology for determining CG CTC in footnote 72. While PG&E's proposed value may comply with this directive, EPUC believes that parties should have an opportunity to examine this calculation through workshops or further proceedings prior to its implementation. The Joint Parties in their protest request that the Commission (1) confirm that a tail CTC rate component for CG DL will not be adopted via PG&E's Advice Letter 2375-E filing, and (2) direct PG&E to revise its proposed Schedule E-DCG to provide that the tail CTC will be calculated using the applicable rate determined by the Commission in a future proceeding (consistent with SCE's proposed CG tariff proposal).

PG&E in its response to EPUC acknowledges that the CTC rate applicable to bundled and DA customers (and in turn to CG) is currently [May 2003] being litigated in the Direct Access phase of R.02-01-011. However, PG&E, at the time, opposed delaying implementation of D.03-04-030. Thus, PG&E included a proposed rate for CTC applicable to only CG DL customers for 2003, based on revenue requirements proposed in R.02-01-011 and the rules set forth in D.03-04-030, footnote 72. Therefore, PG&E concludes that the Joint Parties' concerns are unwarranted, and their requests should be denied.

OP 15 of D.03-04-030 states that "Tail" CTC will be defined and calculated consistent with the text of the order. Footnote 72 explains in part, "The total "tail" CTC revenue requirement will be divided by the total applicable load to derive the CTC rate applicable to DL. The total applicable load includes bundled, DA, and DL customers not otherwise exempted from ongoing CTC pursuant to statute or to this order."

Two points relative to this footnote are critical. One is that the rate is to be developed using the total applicable load, which includes bundled, DA, and DL customers not otherwise exempted from ongoing CTC pursuant to statute or to this (D.03-04-030) order. This would suggest that the same tail CTC rate applies to the customer groups used to derive the rate, in contrast with PG&E's conclusion that a different tail CTC rate applies to CG than to bundled and DA customers. The other critical point is that we adopted neither a CTC revenue requirement nor specific tail CTC rates in D.03-04-030.11

In the CRS cap decision (D.03-07-030 in R.02-01-011) issued several months after the CG CRS decision, we state "The finalization of the actual DWR and URG [Tail CTC] revenue requirement elements is a separate exercise that must be closely coordinated with the DWR proceeding in A.00-11-038 et al. ... In addition to the DWR component, we must finalize and adopt amounts for the URG [Utility Retained Generation or CTC] component of the DA cost responsibility obligation. Since the DWR proceeding in A.00-11-038 et al. does not address URG costs, a separate process is needed to examine URG costs and to adopt a CTC component as prescribed under the total portfolio approach prescribed in D.02-11-022." (D.03-07-030 at p. 11).

Further, we state in that decision, "The concurrent finalization of both the DWR and URG components of the DA CRS should facilitate adopting a final cost responsibility obligation for DA and Departing Load through 2003, including confirmation of the final 2001-02 undercollection balance. For subsequent years beginning with 2004, we conclude that prospective determination of the CTC for each utility can be accommodated within the ERRA proceeding." (at p. 13 and similarly directed in OP 17).

By D.04-02-062, we recently approved the PG&E rate settlement & required a Supplement to modify PG&E's related AL 2465-E. CTC was part of those tariffs but not specifically addressed in the decision. By that AL, PG&E implemented the tail CTC, & DA CRS tariff sheets show line items including tail CTC. These charges should similarly apply to CG not otherwise exempted from the tail CTC.

SCE's Tail CTC was adopted in D.04-04-066.

SCE states in its AL that specific rates for the Tail CTC are not included, as they have not yet been adopted but will be added by advice letter when adopted. EPUC protests that SCE's tariff should clarify that the CTC calculation will be consistent with the calculation specified in D.03-04-030, footnote 72. EPUC requests that SCE be directed to undertake workshops and proceedings necessary to clarify this value, particularly a realistic "market value" for the benchmark in the calculation. The tariff should provide that the charge should become applicable on a prospective basis only upon final determination on the charge. SCE in its response states that EPUC's proposed approach is unnecessary. D.02-11-022 has already established a methodology for calculating the Tail CTC for DA customers, and the same charge can be applied to CG.

In D.03-07-030, we directed in OP 18 that the finalization of the CTC element for year 2004 and thereafter shall be addressed in the ERRA proceeding. In the recently issued D.04-04-066 in SCE's 2004 ERRA proceeding, we adopted a tail CTC for SCE.

SDG&E's Tail CTC was adopted in D.03-02-028.

EPUC protests that SDG&E should implement the CTC methodology adopted by the Settling Parties before the commencement of CTC charges to CG. EPUC argues that the Settling Parties presented a calculation methodology in the Settlement Agreement, recognizing the importance of how the CTC should be calculated in today's environment, as described in Footnote 72 of D.03-04-030. In response to EPUC, SDG&E states that nowhere in D.03-04-030 does the CPUC contemplate revising SDG&E's current CTC rates applicable to DL customers. Nor do the Parties present any evidence that the CPUC has indicated in any other proceeding that a revision to SDG&E's CTC rates is appropriate.

As SDG&E observes, D.03-04-030 did not modify the tail CTC we adopted for SDG&E in D.03-02-028. Therefore, EPUC's protest that SDG&E's tail CTC for CG customers be re-evaluated is denied. We direct SDG&E to apply the tail CTC determined in D.04-02-062 to CG customers not otherwise exempt until that tail CTC is modified.

The utilities shall begin quarterly CG reporting using the format to be developed in the Rule 21 Working Group.

In OP 18 of the CG CRS decision, we directed the Utilities to report quarterly to the Energy Division and the CEC, the amount of customer generation installed under the provisions of that decision. The utilities have awaited further direction on this requirement. The Rule 21 Working Group would provide a reasonable forum to develop a standard reporting format. Therefore, we direct the utilities to develop a straw proposal format (perhaps similar to the reports they are currently providing to the CEC) for discussion at the next Rule 21 working group meeting, but held not less than 30 days after the effective date of this resolution. Within 30 days after the Rule 21 Working Group review, the utilities shall file the format agreed upon with the Energy Division and the CEC. The first quarterly report shall be submitted within 90 days of the effective date of this resolution.

COMMENTS

Public Utilities Code section 311(g)(1) provides that this resolution must be served on all parties and subject to at least 30 days public review and comment prior to a vote of the Commission. Section 311(g)(2) provides that this 30-day period may be reduced or waived upon the stipulation of all parties in the proceeding.

The 30-day comment period for the draft of this resolution was neither waived nor reduced. Accordingly, this draft resolution was mailed to parties for comments, and will be placed on the Commission's agenda no earlier than 30 days from today.

FINDINGS

1. The Commission in Decision (D.) 03-04-030, Ordering Paragraph (OP) 17, directed PG&E, SCE, and SDG&E to file compliance advice letters (ALs) with tariff revisions necessary to incorporate and implement a cost responsibility surcharge (CRS) applicable to customer generation (CG) departing load.

2. PG&E filed AL 2375-E on April 17, 2003 and Supplemental AL 2375-E-A on May 5, 2003. SCE filed AL 1700-E, and SDG&E filed AL 1488-E on April 17, 2003. EPUC and the Joint Parties protested each utility's AL. In addition, CAL SEIA protested PG&E's AL, and CIPA protested SCE's AL.

3. The utilities' advice letters were to be effective on filing, subject to post-filing review by the Energy Division. The utilities have not implemented the tariffs filed in their ALs, awaiting this resolution.

4. As explained herein, the utilities should modify their proposed tariffs to more accurately conform the CG definitions and rates to those adopted in D.03-04-030. As applicable, the utilities should incorporate "Customer Generation" or "CG," into tariff designations, correct date references, remove expired rates, specify excluded load reductions, include a description of the "physical test" to demonstrate islanding, and change the possessive "tenant's" to its plural form.

5. A specific exclusion from the definition of CG is reasonable for dispatchable backup generation used in connection with the dispatch of a load management program sponsored by the Commission, the California Energy Commission, or the California Independent System Operator, or any other successor operator.

6. Utility tariff provisions for measuring and estimating load for use in billing the CTC are reasonable for billing the CG CRS, as proposed by SCE and SDG&E.

7. PG&E's proposed application form for net metering customers is unnecessary and unreasonable.

8. In Resolution E-3847, per PU Code Section 2827, the Commission determined that net metering customers would pay PPP charges on their net consumption.

9. The treatment in proposed tariffs of grandfathered and excepted load is not entirely consistent with the ordering paragraphs of D.03-04-030.

10. The caps adopted in OP 10 on the amount of CG departing load eligible for certain CRS exceptions apply to the CG identified in OP 8 (systems sized over 1 MW but ultra-clean) and OP 9 (CG Other than that defined in Ops 4-8) with more restrictive caps on the latter category.

11. The CRS exception granted for CPUC program eligible CG is limited to a size threshold of 1 MW.

12. For CG up to 1 MW, the CRS exception is tied to CPUC or CEC program eligibility and requires no other specific designation as a clean system to qualify.

13. Exceptions granted in Ops 7 and 8 from HPC apply to the HPC adopted for SCE, as well as any Potential HPC to be adopted for PG&E and SDG&E.

14. D.03-04-030, which is final and unappealable, provides direction concerning the applicability of the bond charge to CG.

15. The bond charge is adopted in A.00-11-038 et Al and is the same value for bundled and DA customers, as well as for CG.

16. D.03-04-030 contains no directive for CG tariffs to contain dispute resolution procedures designed to address disputes specifically involving CG tariffs.

17. The Commission has adopted tail CTC rates for customers of PG&E in D.04-02-062 SCE in D.04-04-066, and SDG&E in D.03-02-028 that should apply uniformly to bundled, DA, and CG not otherwise exempted.

18. The Rule 21 Working Group would provide a reasonable forum for participants to develop a standard reporting format to comply with the quarterly report of installed CG required in OP 18 of D.03-04-030.

THEREFORE IT IS ORDERED THAT:

1. The tariff modifications proposed by PG&E in AL 2375-E/-E-A, by SCE in AL 1700-E, and by SDG&E in AL 1488-E to implement the Customer Generation (CG) Cost Responsibility Surcharges (CRS), as adopted in D.03-04-030 are modified as explained herein.

2. Tariffs shall include the term, "Customer Generation, CG" in their titles and shall, in the provisions which define CG:

3. Utility tariff provisions for measuring and estimating load for use in billing the CTC shall be used for billing the CG CRS.

4. Net metering customers shall pay Public Purpose Program charges based on their net consumption and shall not be required to complete PG&E's Form Number 79-1001.

5. PG&E, SCE, and SDG&E shall modify their proposed tariffs to reflect that the caps adopted in Ordering Paragraph (OP) 10 of D.03-04-030 do not apply to load associated with certain CG CRS exceptions, namely:

6. PG&E, SCE, and SDG&E tariffs shall reflect that the CRS exception adopted in OP 7 requires that the associated CG system meet the 1 MW size threshold and be eligible for either net metering or a CPUC/CEC program. This exception includes PG&E's Regulatory Asset Charge and SCE's HPC.

7. PG&E and SCE tariffs shall reflect that the CRS exception adopted in OP 8 for CG Systems sized over 1 MW but that meet the Public Utilities Code Section 353.2 criteria as ultra-clean and low-emission includes PG&E's Regulatory Asset Charge and SCE's HPC.

8. PG&E, SCE, and SDG&E shall update their CG tariffs to incorporate the bond charge, as adopted in A.00-11-038 et al. and applicable to CG in the manner prescribed by D.03-04-030.

9. PG&E's and SCE's proposed dispute resolution provisions to address disputes specifically involving CG tariffs are disallowed.

10. PG&E, SCE, and SDG&E shall revise their proposed CG rate Schedules to reflect the tail CTC rates as adopted in appropriate other forums described herein, such that the CG tail CTC rate is the same as that adopted for DA and bundled customers. The tail CTC rate component applicable to CG is not adopted via PG&E's Advice Letter 2375-E.

11. Within 90 days of today's date, the utilities shall begin filing Quarterly Reports on installed CG, per OP 15 of D.03-04-030, using the format to be developed by the Rule 21 Working Group. The utilities shall develop a straw proposal format for discussion at the next Rule 21 Working Group meeting, but held not more than 30 days after the effective date of this resolution. Within 30 days after the Rule 21 Working Group review, the utilities shall file the report in the agreed upon format with the Energy Division and the CEC.

12. All protests are resolved as described herein.

13. Within 10 days of today's date, PG&E, SCE and SDG&E shall supplement their advice letters implementing the CG CRS to make the modifications required herein. These supplemental advice letters shall be effective on the date filed, subject to Energy Division's determining that they comply with this Order.

This Resolution is effective today.

I certify that the foregoing resolution was duly introduced, passed and adopted at a conference of the Public Utilities Commission of the State of California held on July 8, 2004; the following Commissioners voting favorably thereon:

            _____________________

1 1. Parties also use the terms "distributed generation," "onsite and over-the-fence generation," and "self-generation" as being interchangeable with "Customer Generation."

2 2. D.03-04-041 modified D.03-04-030 to correct certain clerical errors.

3 3. The CRS cap was evaluated and adopted in D.03-07-030.

4 4. The CRS rate components related to DWR costs must be computed in coordination with the DWR Bond Charge and the DWR Power Charge Revenue Requirement proceedings in A.00-11-038 et al., so that the sum of the remittances from bundled and other customers equals DWR's adopted revenue requirement.

5 5. the link to this web page is: http://www.energy.ca.gov/exit_fees/megawatt_cap.html.

6 6. PG&E in its AL requests Commission clarification as to whether biogas digester customers should also be exempt from what it terms, "other departing load charges" (public purpose program, nuclear decommissioning, and transfer trust amount charges) on load displaced by their generation units. In Ordering Paragraph 6, we exempted Biogas digester customer generation eligible under AB 2228 from any CRS charges but did not address the other charges. PG&E's proposed tariff language in Schedule E-DCG provides an exemption for these customers in this category from all departing load charges.

7 7. Net metering customers pay the cost components covered by the CRS in their net bill, rather than paying a CRS on their departed load.

8 8. However, note in view of SCE's argument that the subsequent section is entitled, "Ultra-Clean and Low-Emission Systems over 1 MW."

9 9. The Joint Parties likewise propose modifying SC 2.e in the same regard for CG sized over 1 MW but that otherwise meets all criteria in Public Utilities Code Section 353.2 as "ultra-clean and low-emissions." The discussion in this section similarly applies to this recommendation.

10 10. The use of the phrase, "or any HPC" in OP 8 in the light of the previous OP must be interpreted as any SCE or potential other utility HPC as specified above.

11 11. Note the future tense in OP 15, which states in relevant part, "Tail" CTC will be defined and calculated consistent with the text of this order."

Top Of Page