D0701039 Figures 1 & 2 and Attachments 1-7
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COM/MP1/MEG/tcg Mailed 1/29/2007

Decision 07-01-039 January 25, 2007

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Order Instituting Rulemaking to Implement the Commission's Procurement Incentive Framework and to Examine the Integration of Greenhouse Gas Emissions Standards into Procurement Policies.

Rulemaking 06-04-009

(Filed April 13, 2006)

INTERIM OPINION ON PHASE 1 ISSUES:

GREENHOUSE GAS EMISSIONS PERFORMANCE STANDARD

LIST OF FIGURES

LIST OF ATTACHMENTS

INTERIM OPINION ON PHASE 1 ISSUES:

GREENHOUSE GAS EMISSIONS PERFORMANCE STANDARD

1. Introduction and Summary1

Today, we adopt an interim greenhouse gas (GHG) emissions performance standard for new long-term financial commitments to baseload generation undertaken by all load-serving entities (LSEs), consistent with the requirements and definitions of Senate Bill (SB) 1368 (Stats. 2006, ch. 598).2 Our adopted emissions performance standard or "EPS" is intended to serve as a near-term bridge until an enforceable GHG emissions limit applicable to LSEs is established and in operation.3 At that time, as directed by SB 1368, we will reevaluate and continue, modify or replace this standard through a rulemaking proceeding, and in consultation with the California Energy Commission (CEC) and the California Air Resources Board (CARB).

As discussed in this decision, an EPS is similar to an energy efficiency appliance standard. If a consumer wants to purchase a new refrigerator in California, for example, he or she has a variety of models to choose from--each with a different upfront purchase price, operating cost and other design attributes. However, at a minimum, each refrigerator must meet the threshold for appliance efficiency established by the standard. Similarly, SB 1368 establishes a minimum performance requirement for any long-term financial commitment for baseload generation that will be supplying power to California ratepayers.4 The new law establishes that the GHG emissions rates for these facilities must be no higher than the GHG emissions rate of a combined-cycle gas turbine (CCGT) powerplant.5

An EPS is needed to reduce California's financial risk exposure to the compliance costs associated with future GHG emissions (state and federal) and associated future reliability problems in electricity supplies. Put another way, it is needed to ensure that there is no "backsliding" as California transitions to a statewide GHG emissions cap: If LSEs enter into long-term commitments with high-GHG emitting baseload plants during this transition, California ratepayers will be exposed to the high cost of retrofits (or potentially the need to purchase expensive offsets) under future emission control regulations. They will also be exposed to potential supply disruptions when these high-emitting facilities are taken off line for retrofits, or retired early, in order to comply with future regulations. A facility-based GHG emissions performance standard protects California ratepayers from these backsliding risks and costs during the transition to a load-based GHG emissions cap. As directed by SB 1368, we have considered the effects on system reliability and overall costs to electricity customers in developing an EPS that will achieve these objectives.6

SB 1368 provides specific direction on many design and implementation aspects of the EPS. We briefly describe that direction in the following summary of today's adopted standard.

1.1. Covered Procurements

SB 1368 describes what types of generation and financial commitments will be subject to the EPS ("covered procurements"). Under SB 1368, the EPS applies to "baseload generation," but the requirement to comply with it is triggered only if there is a "long-term financial commitment" by an LSE. The statute defines baseload generation as "electricity generation from a powerplant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60%."7 For LSE-owned baseload generation, a long-term financial commitment occurs when there is a "new ownership investment." For baseload generation procured under contract, there is a long-term commitment when the LSE enters into "a new or renewed contract with a term of five or more years."8

SB 1368 provides that CCGT baseload powerplants currently in operation, or that have a CEC final permit decision to operate as of June 30, 2007, shall be "deemed to be in compliance" with the EPS. We refer to these § 8341(d)(1) grandfathered powerplants as "deemed-compliant" CCGT powerplants.

During the workshop process and in their comments, parties debated the issue of how the EPS should apply to existing facilities owned by the LSE and used to serve its load (referred to as "retained generation"). Based on our reading of SB 1368, we find that the "new ownership investment" trigger for EPS compliance includes LSE investments in retained generation. Except for deemed-compliant CCGTs, we define that trigger as any LSE investment that is intended to extend the life of one or more units of an existing baseload powerplant for five years or more, or results in a net increase in the existing rated capacity of the powerplant.9 Only those units in a multi-unit generating facility that are being added, replaced or altered must comply with the EPS. A new ownership investment is also triggered if the investment is intended to convert an existing non-baseload powerplant to a baseload powerplant.

However, for deemed-compliant CCGT baseload powerplants, we conclude that the type of investment described above does not necessarily trigger a requirement to comply with the EPS-for either LSE-owned CCGT powerplants (under the "new ownership investment" trigger) or for non-LSE owned powerplants (under the "new or renewal contract" trigger). As discussed in this decision, to construe SB 1368 otherwise would violate fundamental rules of statutory construction by rendering certain sections meaningless or redundant. At the same time, we find that SB 1368 cannot be construed to mean that all new capacity added to a deemed-compliant CCGT powerplant should also be excused from demonstrating actual compliance with the EPS. This would achieve an absurd result by allowing an owner of a deemed-compliant CCGT powerplant to circumvent the EPS by simply co-locating additional units and capacity with existing units at a previously deemed-compliant powerplant.

To avoid this absurd result and give meaning to each section of the statute, we require that units added to a deemed-compliant CCGT powerplant that result in an increase of 50 megawatts (MW) or more to the powerplant's rated capacity must meet the EPS. We select a 50 MW threshold because it demarcates the boundary between significant and minor changes in generating capacity for the purpose of triggering CEC powerplant permitting requirements under Public Resources Code § 25123. This means that an LSE must demonstrate compliance with the EPS whenever the LSE adds units to one of its own deemed-compliant CCGT powerplants if those additions result in an increase of 50 MW or greater to the powerplant's rated capacity. In addition, the LSE must demonstrate compliance with the EPS whenever it enters into new or renewal contract with a deemed-compliant CCGT powerplant to which units have been added that result in an increase of 50 MW or greater to the powerplant's rated capacity.10 In both cases, however, only the added units must meet the EPS.

Some parties urge us to also require that investor-owned utilities demonstrate compliance with the EPS any time the utility seeks rate modifications or submits procurement plans supporting retained baseload generation, irrespective of whether new investments are made to those facilities. This position is inconsistent with the plain language of SB 1368, which provides clear direction as to what triggers the requirement to apply the EPS. Therefore, we only require a demonstration of EPS compliance for retained baseload generation when the LSE makes a new investment in those facilities, as discussed above.

In sum, the interim EPS will apply to the following long-term financial commitments made by an LSE to baseload generation ("covered procurements"):

(1) New ownership investments in baseload generation made by an LSE, defined as:

(2) New contract commitments (including renewal contracts) of five years or greater by an LSE with:

Based on the definition of "powerplant" adopted in this decision, the EPS will generally be applied to each individual generating unit supplying power under the covered procurements listed above. (See Section 4.2.4.)

1.2. EPS Performance Level (Emissions Rate)

Pursuant to SB 1368, the performance level of the EPS must be "no higher" than the emissions rate of a CCGT powerplant.11 However, the statute does not specify the emissions rate for a CCGT powerplant. Based on our review of emissions rates associated with a broad range of CCGT powerplants of varying vintages, we adopt an EPS emissions rate of 1,100 pounds of carbon dioxide (CO2) per megawatt-hour (MWh).12 Based on the record in this proceeding, we find that this level reflects the intent of the Legislature to base the EPS on representative CCGT emissions rates. As discussed in this decision, a 1,100 lbs/MWh standard reasonably accounts for potential CCGT plant "outliers" from the average data on CCGT emissions rates to accommodate those units that utilize dry cooling technologies, are smaller-sized facilities or are located in the desert or at high altitudes. At the same time, our adopted level avoids establishing a performance standard that is representative of the most inefficient, older CCGT powerplants currently in operation. We believe that this is appropriate in light of the statute's grandfathering provisions, which reflect the Legislature's concern that some of the older, less efficient CCGT powerplants in operation may not be able to meet the standard.

1.3. Application of EPS to Contracts

The threshold design issue debated in this proceeding was the application of the interim EPS to contracts. All parties agree that the characteristics of the facility supplying the energy should be considered when applying the adopted standard to new ownership investments. However, there was considerable disagreement over whether the same should apply when considering contract commitments. The issue came down to whether we should apply the performance standard to the underlying facility or to the contracted-for deliveries.

In particular, when a summer product delivered under a new or renewal contract (with a term of five years or greater) from a baseload facility represents less than 60% of that facility's annual average output, some parties recommend that the contract be considered "non-baseload" and therefore exempt from the standard. Similarly, some parties recommend that only the amount of contracted-for deliveries from customer generators to the LSE should determine whether or not the standard applies to the contract.

Several parties also recommend that the capacity factors and emissions rates of multiple powerplants be "blended" when two or more deliver power under a single contract. Under our refrigerator analogy, this approach would permit a customer to purchase two different refrigerator models, one that does not meet the minimum level of efficiency under the appliance standard and one that is more efficient than the standard, such that the average efficiencies of the two meet the required efficiency performance level. The blending approach suggested by parties in the context of the EPS would also permit the averaging of plant capacity factors to determine whether or not the standard applies. In practice, this means that a powerplant generating electricity at a 60% or greater annualized capacity factor (baseload generation) might not be subject to the EPS if the contract also includes deliveries from a powerplant generating electricity at a capacity factor below 60%, depending upon the relative amount of power to be delivered by each facility.

We find that the goals of SB 1368 and this Commission's GHG reduction policies require us to look at the characteristics and emissions of each individual powerplant being contracted for, not just the characteristics of the contracted-for-deliveries or the blended combination of multiple facilities or resources. Indeed, as discussed throughout this decision, it is the very characteristics of the powerplants underlying long-term financial commitments that create the potential financial and reliability risks to California consumers that this Commission and the Legislature seek to reduce through the EPS. Moreover, the language of the statute itself supports a facility-based application of the standard. In particular, SB 1368 directs:

"In determining whether a long-term financial commitment is for baseload generation, the commission shall consider the design of the powerplant and the intended use of the powerplant..." 13

Accordingly, the rules we adopt today require a facility-based application of the EPS. For contracts with multiple generating sources, each specified powerplant must be treated individually for the purpose of determining both the annualized capacity factor and net emissions.

At the same time, we recognize the importance of renewable resources for the achievement of the state's energy policies, as does SB 1368. 14 In the process of meeting the requirements and goals of the statute, we therefore strive to avoid creating impediments to long-term contracting with these resources. As discussed in the following section, we adopt rules for the use of substitute system energy purchases in long-term contracts that provide a reasonable level of contracting flexibility for firming deliveries with renewables without undermining the objectives of SB 1368.

1.4. Unspecified Contracts

SB 1368 also directs us to address long-term purchases of electricity from unspecified sources in a manner consistent with the statute.15 We considered in this proceeding whether it would be consistent with the statute to impute a specific emissions rate to unspecified contracts and, if so, what proxy rate to utilize for this purpose. We use the term "unspecified contracts" to refer to contracts (power purchase agreements) that are not linked to any particular generating source. We also refer to these types of contracts as "system energy" contracts or purchase agreements, and we use these terms interchangeably in this decision.

In order to comply with SB 1368's mandate that we address unspecified sources in a manner consistent with the rest of the statute we must ensure that:

(1) LSEs only enter into long-term financial commitments with baseload generation that comply with the EPS, and

(2) EPS compliance cannot be achieved in a manner that would yield a contrary result, i.e., that results in an increase in long-term commitments with high-emitting sources.

In considering how best to achieve these objectives, we examined various approaches presented during the workshop process and in written comments for imputing an emissions value to unspecified contracts. These include approaches that use 1) Western Energy Coordinating Council (WECC) calculations of average emissions rates for generation activities throughout the western states or by specific geographic region, and 2) the California Net Power Mix information produced by the CEC for power content labeling. Based on the record in this proceeding, we conclude that imputing emissions rates to unspecified contracts would not be consistent with the requirements of SB 1368 for the following reasons.

First, we have difficulty reconciling the concept of imputed emissions rates with the requirements of SB 1368 since, by definition, such proxies do not reflect the actual emissions from the underlying resources. As a result, using imputed emissions rates does not permit us to determine whether a commitment with an unspecified resource is consistent with SB 1368 or simply exacerbates the problems this Commission and the Legislature are trying to address.

Moreover, any method to impute a GHG emissions rate to unspecified resources results in a binary outcome in the context of an EPS - that is, all financial commitments with unspecified resources will either "pass" or "fail" based on the selected level of imputed emissions. As a result, there is enormous pressure to game the methodology and input assumptions used for this purpose, thereby making it very difficult and contentious to implement this particular approach to addressing unspecified contracts. Finally, as discussed in Section 4.12, none of the specific proxy approaches recommended by Commission staff or in parties' comments are reasonable or workable for our purposes, at least not at this time.

Therefore, instead of imputing an emissions rate to unspecified contracts, we require in today's decision that all covered procurements be with specified resources that can demonstrate compliance with the interim EPS, except when substitute system energy is purchased to firm deliveries from specified powerplants under the limited conditions we describe below. For the reasons discussed in this decision, we conclude that addressing unspecified contracts in this manner is consistent with the rest of the statute, as SB 1368 requires.16 Moreover, this treatment of unspecified contracts does not permit gaming that could result in the opposite outcome than the statute intended, i.e., an increasing number of long-term commitments to high GHG-emitting resources.

Based on the record in this proceeding, we also conclude that it is highly unlikely that LSEs will need to enter into any new or renewal power purchase contracts of five years or greater that are unspecified during the transition to a statewide GHG emissions limit. As discussed in this decision, in the event that an LSE must enter into a long-term unspecified contract to address system reliability concerns, it may request Commission consideration of a reliability exemption from this requirement, on a case-by-case basis. Further, today's decision allows for the purchase of substitute system energy to firm deliveries from EPS-compliant, specified powerplants, within certain boundaries, in order to address the need expressed by LSEs and other parties for this type of contracting flexibility.

In view of the above, a requirement that all long-term contracts with baseload generation be with "specified" resources that can demonstrate EPS compliance should not have a significant, if any, impact on an LSE's resource procurement flexibility. By "specified" we mean that the contract identifies the powerplant(s) that will be delivering power under the contract. However, the following circumstances would also comply with our EPS rules: First, if the long-term contract specifies that power will be delivered exclusively from pre-approved renewable technologies or resources (see Section 1.6 below) and there are assurances in the contract to that effect, then the contract would comply with the EPS even if none of the generating sources are specified. Second, if a group of powerplants from which power will be delivered under a contract is specified, and there are assurances in the contract that deliveries will only be from one or more of the powerplants in that group and each of those that are baseload powerplants would individually pass the EPS, then the contract would comply with the EPS. The burden is on the LSE to provide sufficient documentation to demonstrate compliance with the EPS under these circumstances.

As discussed in this decision, today's adopted EPS rules with respect to unspecified contracts are also consistent with our discussion of emissions registration in Decision (D.) 06-02-032 and a logical interim step towards the implementation of Assembly Bill (AB) 32 (Stats. 2006, ch. 488).17 As we note in today's decision, other jurisdictions have developed specific resource tagging mechanisms to track generation attributes, including GHG emissions, of resources within their control areas. In our view, it is entirely feasible to implement a program that tracks the GHG emissions of all generating units, and that would enable marketers and other sellers of unspecified resource contracts to assign a reasonable and accurate GHG emissions profile to their contracts. This should be the strategy pursued by California to deal with emissions from any unspecified resource contracts that LSEs may wish to pursue; however, as the record shows, this is not a likely pursuit for the types of LSE long-term procurements subject to the interim EPS.

While LSEs have stated that they are not likely to pursue long-term unspecified contracts as a general rule, they do intend to continue to negotiate long-term contracts with specified powerplants that contain "substitute energy provisions," i.e., provisions that permit the seller to substitute system energy on a short-term basis as needed for operational or efficiency reasons. We are persuaded from the comments in this phase of the proceeding that these types of provisions can provide greater performance assurance at more moderate price to ratepayers, and that appropriate restrictions to their usage can be put in place to guard against the intentional sourcing of energy from high carbon intensive baseload resources. Accordingly, based on proposals submitted by Pacific Gas and Electric Company (PG&E) and the Sacramento Municipal Utilities District (SMUD) in this proceeding, we permit LSEs to enter into contracts with a term of five years or longer that include provisions for substitute system energy purchases under the following circumstances:

1. The contract is with one or more specified powerplants, each of which is EPS-compliant under our adopted rules.

2. For specified contracts with non-renewable resources or dispatchable renewable resources (or a combination of each), substitute energy purchases for each specified powerplant are permitted up to 15% of forecast energy production of the specified powerplant over the term of the contract, provided that the contract only permits the seller to purchase system energy under either of the following conditions:

a) The contract permits the seller to provide system energy when the powerplant is unavailable due to a forced outage, scheduled maintenance or other temporary unavailability for operational or efficiency reasons; or

b) The contract permits the seller to provide system energy to meet operating conditions required under the contract, such as provisions for number of start-ups, ramp rates, minimum number of operating hours, etc.

      A "dispatchable" renewable resource for the purpose of this rule is one that is not defined as "intermittent" under section 3 below.

3. For specified contracts with intermittent renewable resources (defined as solar, wind and run-of-river hydroelectricity), the amount of substitute energy purchases from unspecified resources is limited such that total purchases under the contract (whether from the intermittent renewable resource or from substitute unspecified sources) do not exceed the total expected output of the specified renewable powerplant over the term of the contract.

1.5. Calculation of Emissions Associated with Cogeneration

SB 1368 requires us to adopt a methodology for calculating the emissions rate associated with cogeneration facilities that recognizes both the thermal output (heat or steam) and electrical output associated with cogeneration.18 In today's decision, we consider several approaches to this requirement and adopt the "conversion method." Under this method, the emissions rate is calculated by dividing the total GHG emissions from a cogeneration facility by the sum of its kilowatt-hour (kWh) output plus the usable thermal energy output (expressed in kWh) produced by the facility. For this calculation, the thermal energy output is converted from British thermal unit (Btu) into a kWh equivalent using the standard engineering conversion factor of 3413 Btu per kWh.

There was some debate in this proceeding over how to define "useful thermal energy" for this calculation. We adopt the definition used by the Federal Energy Regulatory Commission (FERC) in its regulations mandating the minimum efficiencies of a cogeneration qualifying facility (QF).19 Based on this definition, the calculation of emissions rates for cogeneration facilities should include the thermal energy that is actually intended to be delivered to the thermal host, and not include remaining thermal energy intended to be exhausted as waste heat.

As discussed in this decision, all existing cogeneration facilities complete an annual questionnaire submitted to the interconnecting utility to demonstrate compliance with FERC efficiency requirements. On this form, the cogenerator presents monthly and annual values for energy input, useful power output and useful thermal output. For the purpose of the interim EPS, we will base a cogenerator's emissions rates on the values presented in these questionnaires, which are readily available from the interconnected utility. For new cogeneration facilities, when this questionnaire has not been submitted to the utility, the EPS will be determined based on reasonably projected emissions of the facility, which can be based on readily available information in FERC Form 556, required for QF certification.

We emphasize, however, that we adopt the above approach for calculating and documenting cogeneration emissions rates for the limited purpose of demonstrating compliance with the interim EPS. Our determinations today are in no way intended to prejudge or predetermine what approach may be established in the context of our Procurement Incentive Framework or under the statewide GHG emissions limit envisioned under AB 32.

1.6. Emissions Rates of Renewables and "Null" Renewable Power

As summarized in Figure 1, the record in this proceeding supports an upfront determination that the following renewable resources and technologies are EPS-compliant:

· Solar Thermal Electric (with up to 25% percent gas heat input)

· Wind

· Geothermal, with or without reinjection

· Generating facilities (e.g., agricultural and wood waste, landfill gas) using biomass that would otherwise be disposed of utilizing open burning, forest accumulation, landfill (uncontrolled, gas collection with flare, gas collection with engine), spreading or composting.

In particular, the record shows that electric generation using biomass (e.g., agricultural and wood waste, landfill gas) that would otherwise be disposed of under a variety of conventional methods (such as open burning, forest accumulation, landfills, composting) results in a substantial net reduction in GHG emissions. This is because the usual disposal options for biomass wastes emit large quantities of methane gas, whereas the energy alternatives either burn the wastes that would become methane or burn the methane itself, generating CO2. Since methane gas is on the order of twenty to twenty-five times more potent as a GHG than CO2, and since methane has an atmospheric residence time of twelve years, after which it is converted to atmospheric CO2, trading off methane for CO2 emissions from energy recovery operations leads to a net reduction of the greenhouse effect.20

In practice, this means that an LSE does not have to demonstrate compliance with the EPS for long-term financial commitments with baseload generation utilizing any of the renewable resources and technologies listed above. Such commitments get an automatic "pass" through the gateway screen described below. If and when there is sufficient data so that parties believe that the Commission could make determinations to pre-approve additional renewable resources and technologies, parties may file a Petition for Modification of this decision to augment the above list. There was considerable debate over how to attribute emissions factors to renewable resources that have sold off their renewable energy credits or "RECs." The term "null renewable power" refers to those renewable resources that have transferred their renewable attributes through the sale of RECs. In the context of making the EPS "go, no-go" commitment decision, parties raised the issue of whether renewable resources should be "stripped" of their GHG emissions attributes if they have sold RECs and if so, what emissions rate should be assigned to that null renewable power for the purpose of evaluating EPS compliance.

As discussed in this decision, among other potential purposes, the trading of RECs would provide a flexible compliance option to LSEs for meeting their Renewable Portfolio Standard (RPS) obligations.21 We have identified the investigation of a tradable REC system as one of the tasks for Rulemaking (R.) 06-02-012 and plan to initiate this investigation during 2007. We therefore cannot predict at this time whether, how or when a regulatory REC market will develop in California. Some parties propose that we defer the issue of how to treat null renewable power for the purpose of EPS compliance until we complete our investigation of a tradable REC system. However, we reject this approach because of the potentially dampening effect that this uncertainty could have on the development of renewable resources.

For the purposes of demonstrating compliance with the interim EPS, we determine that the emissions rate for renewables should be calculated based on the operations and emissions profile of the renewable resource, irrespective of whether RECs associated with that facility are sold. We reach this determination for several reasons. In particular, we conclude that stripping renewables of their emissions profile if RECs are sold could easily create a "perverse" result; namely, to discourage long-term commitments with renewable generators that have zero, low or even negative net GHG emission profiles, in favor of higher emitting facilities.

Moreover, in the context of EPS compliance, we find that retaining the emissions attributes of the renewable facility when RECs are sold does not create a double counting problem, as some suggest in this proceeding. This is because the EPS is a "go-no go" investment standard separate from RPS compliance, and as discussed above, each facility has to pass the EPS on its own emissions-generating merits. In other words, a high-emitting facility would not be able to use a purchased REC for the purpose of reducing (or blending) its emissions to demonstrate compliance with the EPS. Therefore, there is nothing to double count here, since RECs would not have any value for EPS compliance. Moreover, our treatment of RECs in the context of the EPS is not inconsistent with § 399.12, as amended by SB 107, which provides that a REC "includes all renewable and environmental attributes associated with the production of electricity" (emphasis added), not discrete investment decisions.

For these and other reasons, we determine that the emissions profile of a renewable resource will not change for the purpose of demonstrating EPS compliance if or when the owner sells the RECs associated with that baseload facility. This also means that purchased RECs cannot be used by an LSE to lower the emissions of a baseload facility for the purpose of demonstrating EPS compliance. However, we emphasize that today's determination on how to treat null renewable power and associated RECs is specific to the application of the interim EPS. This determination in no way guarantees that null renewable power will be assigned a zero or low GHG emissions value in the context of either the Procurement Incentive Framework we are implementing in Phase 2 of this proceeding, or the statewide GHG emissions limits adopted by the Legislature in AB 32.

1.7. Exemptions from the Interim EPS

As discussed above, SB 1368 exempts from the EPS any CCGT baseload powerplant that is in operation, or that obtains a final CEC permit to operate by June 30, 2007. By today's decision, we provide for the possibility of a reliability exemption to the EPS that is very limited in scope. We also provide for the possibility of filing a petition for modification to obtain relief from the requirements of this decision in the event of extraordinary circumstances not contemplated by SB 1368 and this decision.

First, we allow for case-by-case exemptions to the EPS if the LSE can demonstrate that a long-term unspecified contract or commitment to a non-compliant specified powerplant is necessary to address system reliability concerns. As discussed in this decision, we believe that this type of exemption will probably not be needed, given the definition of covered procurements and other design aspects of the EPS. Nonetheless, we allow for the possibility of granting this limited exemption, on a case-by-case basis, in the event that unexpected reliability problems arise during implementation.

Second, we permit an LSE to file a petition for modification in the event of "extraordinary circumstances, catastrophic events, or threat of significant financial harm" that may arise during EPS implementation due to unforeseen circumstances not contemplated by SB 1368 and this decision. As in the case of a reliability exemption, our consideration of such a petition for modification comes with a heavy burden of proof on the LSE, as it must be based on extreme (and therefore highly unlikely) circumstances. Both the reliability exemption and the request for relief due to "extraordinary circumstances" must be pre-approved on a case-by-case basis by the Commission. As directed in this decision, LSE requests for pre-approval of a reliability exemption shall be made by application. LSE requests for relief from the requirements of this decision due to "extraordinary circumstances" shall be made by filing a petition for modification.

Additional exemptions from the EPS were proposed in this proceeding for (1) "small size" facilities, contracts or service territories, (2) research development and demonstration (RD&D) projects with the potential to develop a lower-emitting resource in the future, (3) gas-fired cogeneration and (4) case-by-case exemptions based on the cost of compliance. These recommendations were debated on both sides in parties' comments and legal briefs. For the reasons discussed in Section 4.8, we find that none of these exemptions are reasonable in light of the policy objectives and statutory requirements of SB 1368.22 We also find that requiring QFs to comply with the GHG emissions performance standard is consistent with federal law, and conclude that we cannot grant QFs an exemption from the requirements of SB 1368 as some parties request.

In addition, a few parties recommend that we permit LSEs to obtain "offsets," whereby the LSE would have the option to offset emissions from a high-emitting baseload resource with GHG emissions reductions secured elsewhere to bring it into compliance with the EPS. Continuing with our appliance efficiency analogy, permitting the LSE to comply with the EPS in this manner would be akin to allowing customers to purchase refrigerators that do not meet the minimum level of efficiency for their own home, as long as they create offsetting efficiency savings in a neighbor's home, e.g., by changing out enough inefficient light bulbs with efficient ones (or paying a third party to do it). One party also suggests that we allow the LSE to average emissions rates across its entire procurement portfolio in demonstrating compliance with the standard.

We conclude that permitting LSEs to comply with the EPS through offsets or portfolio-averaging would compromise the very purpose articulated by this Commission and the Legislature for establishing an interim EPS in the first place. As discussed above, the EPS establishes a minimum level of acceptable GHG emissions performance for any baseload generation facility that represents a new long-term financial commitment to California. This serves a fundamentally different purpose, reflecting different policy objectives, than programs to reduce GHG emissions through a portfolio-wide cap, cap-and-trade programs or programs that permit LSEs to create or purchase offsets to meet an emissions cap or performance standard. As discussed in Section 5.4, the purpose of these programs is to provide varying degrees of compliance flexibility when the primary policy goal is to reduce the overall level of emissions generated through procurement activities.

The objective of the interim EPS, on the other hand, is to ensure that there is no "backsliding" as California transitions to a statewide GHG emissions cap. This objective cannot be accomplished if LSEs are permitted to comply with the standard by diluting the emissions from high-emitting powerplants through portfolio averaging, or by increasing the permissible level of emissions for non-compliant powerplants through offsets or other means.23 These options would only serve to disguise the types of problems that the EPS is designed to avoid, e.g., the high costs of future plant retrofits and reliability disruptions as it becomes increasingly difficult for these high-emitting facilities to comply with GHG emission regulations, such as the AB 32 declining cap on statewide GHG emissions.24

Moreover, as staff and many parties point out, a workable offsets program cannot be designed and implemented within the timeframe contemplated for an interim EPS, particularly in light of the SB 1368 statutory requirement that an enforceable EPS be put in place no later than February 1, 2007.

For these reasons, we do not permit offsets or portfolio averaging in the context of the adopted interim EPS. In the context of a load-based cap, however, we fully intend to evaluate a broad range of flexible compliance options as we proceed to implement the Procurement Incentive Framework during Phase 2 of this proceeding. Pursuant to AB 32, flexible compliance options will also be evaluated as California proceeds to implement the emissions limits required under that new law on a statewide basis.25 As we stated in D.06-02-032, we will focus our efforts during Phase 2 on ensuring that the compliance options that we do permit under the Procurement Incentive Framework are credible, verifiable and administratively feasible. During Phase 2, we intend to carefully explore the pros and cons of alternate proposals for offsets, trading, banking and borrowing and other compliance options before making our final determinations. Throughout the process, we will closely coordinate with CARB, the Governor's Climate Action Team as well as other state, regional or federal agencies that are exploring design options for cap-and-trade programs.26

1.8. Demonstrating Compliance with the EPS

Attachment 2 presents a flowchart illustrating how the EPS will be applied under today's adopted rules, consistent with SB 1368. We take a gateway screen approach, as recommended by Commission staff and all the parties to this proceeding. This approach is consistent with the intent of SB 1368, which directs us to look to the "design and the intended use" of the powerplant under § 8340(a). Moreover, as staff and the parties point out, a gateway screen approach is the most practicable and enforceable manner in which to determine EPS compliance.

As illustrated in Attachment 2, this approach applies a series of questions/criteria to first establish whether or not the LSE's financial commitment represents a covered procurement subject to the EPS. If it is, then the commitment is screened to ensure that it meets the performance level of the standard, e.g., that the associated GHG emissions rate does not exceed 1,100 lbs of CO2 per MWh. Once the financial commitment successfully passes through the gateway screen, the LSE has demonstrated EPS compliance for that particular commitment. Ongoing Commission review or monitoring of the facilities underlying that commitment is not required.

We also describe in today's decision the procedures by which an LSE demonstrates compliance with this gateway screening process. Currently, Southern California Edison (SCE), San Diego Gas & Electric Company (SDG&E) and Pacific Gas and Electric Company (PG&E) bring all power purchase contracts with terms of five years or longer before this Commission for review and pre-approval by filing either an advice letter or application. As discussed in Section 5.1, we utilize these existing procedural vehicles for reviewing and pre-approving PG&E, SCE and SDG&E's covered procurements with respect to EPS compliance.

On the other hand, we do not currently require electric service providers, community choice aggregators or the small electrical corporations to submit procurement plans or power purchase contracts to the Commission for pre-approval. For these entities, we establish today an annual advice letter filing by which they can attest "after-the-fact" that they are in compliance with the EPS. They can also request Commission pre-approval of covered procurements as EPS-compliant (but are not required to) by advice letter.

In today's decision, we also clarify how to determine whether contracts that have a term of less than five years are "linked" and therefore should be treated as a single contract for the purpose of applying our adopted EPS rules. . In addition, we clarify the documentation requirements for all LSE compliance submittals, and approve the showings of "alternative compliance" by multi-jurisdictional electrical corporations pursuant to § 8341(d)(9).

1 Attachment 1 describes the abbreviations and acronyms used in this decision.

2 Attachment 3 presents the full text of SB 1368. The statute defines LSEs as "every electrical corporation, electric service provider, or community choice aggregator serving end-use customers in the state." (Public Utilities Code § 8340(h), added by SB 1368.) All subsequent references to sections refer to the Public Utilities Code, unless otherwise specified.

3 We use the terms "GHG emissions performance standard," "standard," and "emissions performance standard" (or "EPS") interchangeable throughout this decision.

4 SB 1368 directs this Commission to adopt an EPS for all LSEs, as that term is defined above, and directs the CEC to implement an EPS for all of the local publicly owned electric utilities (by June 30, 2007) consistent with the standard we adopt herein. (§ 8341(e)).

5 Throughout this decision, we use the term CCGT powerplant to refer to a "combined cycle natural gas plant" as defined in SB 1368. More specifically, CCGT powerplant refers to a powerplant that "employs a combination of one or more gas turbines and steam turbines in which electricity is produced in the steam turbine from otherwise lost waste heat exiting from one or more of the gas turbines." (§ 8340(b).)

6 § 8341 (d)(6).

7 § 8340 (a).

8 § 8340 (j).

9 "Rated capacity" refers to the plant's maximum rated output under specific conditions designated by the manufacturer and usually indicated on the nameplate physically attached to the generator.

10 For the purpose of establishing when there has been a 50 MW addition, the existing rated capacity will be determined as follows: 1) for all CCGT plants that are in operation on the effective date of this decision-the rated capacity of the plant that is operating, or 2) for all other plants (or additions to plants) that obtain a CEC final permit to operate by June 30, 2007-the rated capacity authorized by the permit.

11 § 8341(d).

12 We discuss in Section 4 below why today's adopted standard focuses on CO2 emissions.

13 § 8341 (b)(4), emphasis added.

14 See SB 1368, Section 1 (c) and (d).

15 § 8341(d)(7).

16 § 8341 (a), (b)(1), (b)(3) and (d)(1).

17 See D.06-02-032, p. 38. Among other things, AB 32 requires CARB to adopt a statewide GHG emissions limit equivalent to the statewide GHG emissions levels in 1990, to be achieved by 2020, in consultation with this Commission.

18 § 8341(d)(3).

19 A QF is a generating facility that meets the requirement for QF status under federal law and FERC regulations governing such facilities. QFs can be cogeneration facilities of any size or small power production facilities (up to 80 MW) where the primary energy source is renewable.

20 For the biomass technologies identified above, which utilize landfill gas, agricultural and wood waste as the biomass fuel source, by definition there are no emissions associated with growing the fuel. As discussed in this decision, an LSE entering into a long-term financial commitment with a biomass generating project where growing the fuel is required will need to calculate net emissions taking into account the emissions associated with "growing," as well as "processing and generating" the electricity from the fuel source pursuant to § 8341(d)(4).

21 By law, electricity generated from eligible renewable energy resources must equal at least 20% of the total electricity sold to retail customers in California per year by December 31, 2010. (SB 107, Stats. 2006, ch. 464.)

22 As we discuss in this decision, the Legislature specifically directs that we not count CO2 injected into geological formations (so as to prevent releases into the atmosphere) in the calculation of net emissions. Therefore, although we do not adopt a blanket RD&D exemption from the EPS, we do clarify how the LSE may apply for Commission pre-approval of covered procurements utilizing such CO2 sequestration projects. In implementing §§ 8341(d)(2) and (5), we also clarify that we will determine EPS compliance for such covered procurements based on reasonably projected net emissions over the life of the facility, which recognizes that the sequestration project may become operational after the powerplant comes on line or the LSE enters into the contract. We will include in our review any emissions-related provisions that may be required through contract and/or permit conditions.

23 For similar reasons, we also reject the notion of establishing "price caps" for complying with today's adopted EPS, as one party proposes. As discussed in Section 4.8.5, price caps would allow the LSE to build or enter into long-term contracts with high GHG-emitting plants without any reduction in those plants' emissions, which is not consistent with the purpose of establishing an interim EPS in the first place.

24 AB 32, Cal. Health & Saf. Code § 38562(c).

25 AB 32, Cal. Health & Saf. Code § 38561, § 38570.

26 D.06-02-032, p. 44.

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