Final Workshop Report:

Interim Emissions Performance Standard Program Framework, R.06-04-009

June 21-23, 2006

Prepared by Commission Staff, October 2, 2006

The California Public Utilities Commission ("CPUC" or "Commission") convened a three-day workshop in its climate change policy proceeding, R.06-04-009, on June 21-23, 2006 in San Francisco. This workshop considered the design and implementation structure of an interim emissions performance standard ("EPS") program prior to implementation of a greenhouse gas (GHG) cap that would apply to the three major investor-owned electric utilities ("IOUs")¹, its jurisdictional energy service providers ("ESPs"), and community choice aggregators ("CCAs") that operate within an IOU's territory. This Report outlines the background and purpose of the workshops, reviews participants' comments on key points, summarizes the advantages and disadvantages that participants attributed to key issues associated with an interim EPS program, and includes a revised version of the staff proposal for an EPS program. Appendices include a list of the workshop participants, a summary of the written comments on the Draft Workshop Report, the data requested at the workshop and subsequent responses, the revised staff proposal posed for post-workshop comments, questions posed to parties for post-WS comment, and the text of SB1368.

For purposes of clarity, "Final Proposal" or "Final Staff Proposal" refers to the staff proposal submitted today as part of the Final Report. "Revised Proposal" or "Revised Staff Proposal" refers to the staff proposal circulated for comment as part of the Draft Report issued on August 21, 2006. For reference, this revised proposal is included as Appendix H.

This Final Report incorporates opening comments on the Draft Workshop Report submitted by parties on September 8, 2006 and reply comments submitted on September 15, 2006. Where appropriate, staff has also incorporated the relevant statutory guidelines and requirements adopted in SB1368 and AB32 as they relate to the design of an interim EPS. These pieces of legislation were signed into law on September 29 and September 27, 2006, respectively.

Throughout this report, we use the term "greenhouse gas"² or "GHG" (rather than "carbon" or "CO2") to refer to the types of emissions that would be addressed in an EPS, even though CO2 reductions may be the primary focus in the near term. This recognizes that the full scope of GHG emissions will ultimately need to be included in the strategies to mitigate climate change.

I. Background and Purpose of the Workshop

In the October 6, 2005 GHG Policy Statement, the Commission describes a GHG emissions performance standard that would limit the GHG emissions levels for all new utility-owned generation and all long-term procurement contracts to "no higher than the GHG emissions levels of a combined-cycle natural gas turbine."

The Commission's objective in scheduling this workshop was to identify key issues to consider when contemplating an EPS, and to develop an EPS program proposal that would incorporate policy, design and implementation issues identified by parties and staff. The EPS discussion and proposal was limited to an interim GHG EPS program intended to serve as a near-term bridge to the load-based GHG cap adopted by the Commission in D.06-02-032, and to the extent possible, form consensus among parties. The development of an interim GHG EPS is identified as "Phase 1" of R.06-04-009, with "Phase 2" focusing on design and implementation of a load-based cap.

As discussed at the May 10, 2006 Pre-Hearing Conference on the matter, and subsequently described in the June 1 Ruling, Phase 1 will address the following key questions:

(a) Should the Commission adopt an interim GHG EPS to guide ongoing electric procurement decisions while it takes the necessary steps to fully implement D.06-02-032?

(b) If the Commission elects to adopt such a standard, how should it be designed and implemented so that it can be put in place quickly to serve this purpose?

The language of the OIR indicates that the Commission did not intend to restrict the design of the performance standard to the one specifically set forth in the 2005 GHG Policy Statement. In the context of Phase 1, however, the specific purpose of an interim performance standard may dictate many of the relevant design and implementation parameters. As discussed at the PHC, certain "bells and whistles" (e.g., offsets) to a performance standard that the Commission may wish to consider in the context of a load-based cap do not appear to be feasible in the context of an interim standard that needs to be put in place quickly.

Accordingly, deviations from the performance standard design set forth in the 2005 GHG EPS Policy Statement may be considered in Phase 1, but only to the extent that such deviations would not significantly delay the implementation of an interim EPS.

To help focus party preparation for this workshop, the assigned Administrative Law Judge (Judge Gottstein) circulated a proposed agenda and pre-workshop questions prepared by CPUC staff on May 31, 2006. Judge Gottstein directed interested parties to file pre-workshop comments in response to the questions posed and to identify other issues, if any, that the CPUC should take into consideration at the workshops. A list of those parties filing opening and reply comments on the Draft Workshop Report is included in the summary of those comments presented in Appendix A of this report.

Approximately 90 individuals, representing about 50 different stakeholders, attended one or more days of the workshop. Appendix B presents a list of these workshop participants. This workshop report cannot fully reflect all of the discussion throughout the three-day workshop. Instead, the sections entitled "Workshop Participant Comments" in the body of this report are intended to highlight the major issues raised during the discussion, rather than to present a detailed summary of each participant's position.

II. Workshop Structure and Scope

Based upon the proposed agenda included in the June 1 Ruling and pre-workshop comments, staff structured the workshop to address three overlapping categories relevant to the design and implementation of an EPS: 1) Policy Overview and Basic EPS Structure, 2) Standard-setting and Implementation Details, and 3) Design Summary, Implementation Issues, and Next Steps. In addition, a staff straw proposal was presented for discussion on Days 2 and 3. Workshop discussion was structured to identify policy issues of primary concern when considering whether to pursue an EPS program, followed by discussion of key design and implementation issues associated with an EPS program.

On May 31, 2006 CPUC staff further clarified the scope of the workshop by including pre-workshop questions (see Appendix C). On June 1, 2006 Judge Gottstein's Ruling³ provided additional direction on the scope of phase 1 and indicated the two primary umbrella issues to be addressed: (a) Should the Commission adopt an interim GHG emissions performance standard to guide ongoing electric procurement decisions while it takes the necessary steps to fully implement D.06-02-032; and (b) If the Commission elects to adopt such a standard, how should it be designed and implemented so that it can be put in place quickly to serve this purpose? Judge Gottstein also asked parties to present their best available assessment costs, benefits, and co-benefits.

The purpose of this workshop was strictly to discuss phase 1 issues which are limited to the concept and design of an interim EPS. Phase 2 issues related to development and implementation of a greenhouse gas cap were expressly not included for discussion at the workshop, or at the phase 1 Pre-Hearing Conference or in subsequent materials. Phase 2 issues will be addressed in that phase of the proceeding.

CPUC staff and consultant⁴ began the workshop with an overview of the major areas to be considered in each of the three days: policy overview and basic EPS structure (Day 1); standard-setting and implementation details, including discussion of a staff straw proposal (Day 2); EPS design summary and implementation details, including continued discussion of the staff straw proposal (Day 3) ⁵. The data requested at the workshop are attached as Appendix E. In the sections below, we summarize the workshop discussion on a day-by-day basis. Readers are encouraged to refer to the materials in the appendices as they review this summary.

III. Policy Overview and Basic EPS Structure Discussion (Day 1)

CPUC staff provided an overview of the context for consideration of an interim EPS, and a brief overview of the existing EPS Policy Statement. Emphasis was placed on pursuing focused discussion to identify areas of agreement, where possible, and to identify key issues associated with consideration and/or design of an interim EPS.

The structure of discussion followed the order of questions posed for pre-workshop comment. The responses have been categorized and summarized based upon the flow of discussion during the workshop days.

A. Workshop Participant Comments on Policy Overview Questions: General Considerations

Staff then posed the following "Policy Overview" questions for discussion to identify the key areas of agreement and of concern.

1a. Should the Commission adopt an interim EPS to guide ongoing electric procurement decisions pending adoption of a long-term cap and trade program? Identify principal policy arguments, pro and con

Responses to Q1a

_ The existing carbon adder policy adopted and implemented by the CPUC makes an EPS unnecessary as it achieves the same goal of preventing backsliding to higher emitting resources than those currently included in the IOU and ESPs portfolio mix. (IEPA)

_ An EPS supports the Governor's Executive Order setting GHG emission reduction goals. An EPS should stay in effect even after a cap and trade program is implemented. (NRDC)

_ The adder is complimentary to EPS but does not replace. Open question as to how an EPS might interact with reliability risks. IOUs should include an EPS scenario with existing procurement plans. (TURN)

_ The CPUC could increase the adder amount to meet some of the same near-term goals as an EPS. However, an EPS essentially requires existing ratepayers to pay for externalities associated with GHGs while the existing adder places the bulk of the burden on future generations as it does not take into account costs beyond a certain price point and is advisory only. The adder still allows high emitting plants into the procurement mix whereas an EPS sets a minimum standard. (CEC)

_ The CPUC already has oversight over new LT contracts anyway so EPS is unnecessary. (SCE)

_ The CPUC should set clear requirements for procurement up front. Before going through an involved RFP process requiring time and money, LSEs should know with certainty the CPUC's contract and generation requirements. Waiting for the CPUC to weigh in at the end of the process is counter-productive. Issues: costs, reliability, support adder. Concerned about excluding too many resources. (PG&E)

_ The effect of an EPS impact would be insignificant as the CPUC already has existing policies that prevent backsliding such as the RPS and EE. (EPUC)

_ The CPUC has oversight of long-term procurement. LSEs need clear and unambiguous signal to prevent investment in new power plants and contracts of highest emitting variety. New coal is an issue. The EPS provides the clear signal needed to ensure clean energy investment. (GPI)

_ The adder is problematic because it's difficult to determine the "right" value. Development of an interim EPS may interfere with development of a cap and trade program, and new technologies may be disincented. Further, relying on the knowledge by LSEs that a cap will be in place by a given near-term date can give sufficient incentive to contract for low-emitting resources now. (SF Community Power)

_ Investment decisions are happening now in the interior west including new non-advanced coal facilities and transmission to bring coal to California. A carbon adder is anticipated compliance cost, whereas an EPS looks at an actual emissions threshold. (WRA)

_ The carbon adder allows for consideration of other attributes- reliability, costs, etc, that an EPS does not. EPS seems to draw a line in the sand. (SDG&E)

_ Ongoing monitoring of contracts and investments would create uncertainty and significantly affect market. (IEPA, PG&E)

_ An EPS should include dispatch consideration and peakers. (League of Women Voters)

_ An EPS is overly prescriptive regarding technology choice. (Constellation)

1b. If the Commission decides to adopt an interim EPS, what goals are most important in guiding its design and implementation?

Responses to Q1b

_ The purpose of an EPS is to prevent investment and contracting with resources that are higher emitters than what we have in the system today and therefore prevent "backsliding." CA is the load center in WECC. Need to lead. (GPI)

_ General concerns expressed regarding the possibility of developing overly prescriptive policies. (EPUC)

_ EPS necessary to prevent the increasing emissions prior to implementation of a future cap. Encourages technological innovation. (NRDC)

_ EPS should be comprehensive and apply to all LSEs. (PG&E)

_ Don't include ESPs. Emissions are negligible from ESPs and long-term contracting is limited. (AReM)

_ EPS should be designed to transition well to / integrate with a cap. (SF Community Power)

_ Appropriate design depends on whether EPS would apply to existing and/or new facilities. (SCE)

_ Need to know how an EPS would link to existing procurement policies. (Constellation)

B. Workshop Participant Comments on Basic EPS Structure

Staff then posed the following EPS Basic Structure questions for discussion to identify the key areas of agreement and of concern.

2. If an interim EPS is adopted, to which Load Serving Entities (LSEs) should it

apply?

Responses to Q2: To which LSEs should an interim EPS apply?

_ Energy Service Providers (ESP) should not be included in an EPS program as their procurement process is not the same as IOUs and they represent a small portion of total load. Implementation delays and extra costs would be likely if ESPs were required to participate. (AReM)

_ ESPs can have a significant impact on market, especially if wholesale costs drop and as DWR contracts expire, ESPs can sign up more contracts. The argument that ESPs don't enter into significant long-term contracts is not persuasive. If they don't enter into long-term contracts, then ESP compliance with the program would be negligible. If they do enter into significant long-term contracts, they should be included. Either way, it makes sense to include them as part of an EPS.

Prefer comprehensive statewide policy including munis. If munis are not included, it then creates competitive problems for utilities statewide. Need to understand impacts of CA energy markets if munis are exempt from program Programs need to be at minimum statewide, and policies need to coordinate with legislation. (PG&E, SCE)

_ The CPUC Long-Term Procurement Docket has teed up the issue for Phase II as to how ESPs may be required to come into procurement process. (CPUC Energy Division)

_ Open issue of how to deal with system contracts and allocation for multi-state, multi-jurisdictional entity. (Mid-American/PacifiCorp)

_ The program should focus on the public good and be applied to munis also. (League of Women Voters)

_ Munis do not need to be included in an EPS program as they are more responsive than IOUs. (NorCal Power Agency)

_ CPUC sets standard that creates pressure on other entities, e.g. munis. The program should aim to accomplish all that it can for CPUC jurisdictional LSEs. (GPI)

_ An EPS program needs to be coordinated with legislation. (IEPA)

3. Over what time frame should an interim EPS be implemented?

Responses to Q3: Over what timeframe should an interim EPS remain in place?

_ Current CPUC procurement process reviews a significant number of short-term contracts. The number of contracts of 5 years and greater are much more limited. Currently reviewing one long-term contract submitted by PG&E. Anticipate SCE will soon file long-term contracts with the CPUC as well. (CPUC Energy Division).

_ EPS should remain in place until a more comprehensive program is implemented. Note that the program doesn't necessarily have to be a CPUC program. (PG&E)

_ The CPUC should not pursue an EPS program and should instead wait for state, regional, or federal action. (EPUC)

4. To which power sources should an EPS apply?

Responses to Q4: To which power sources should an interim EPS apply?

_ Program should include contracts/facilities of 5 MW and greater as that is consistent with SGIP. The EPS should apply to all long-term contracts including IOU owned, repowered facilities. IGCC should be included if sequestration is part of the technology. (NRDC)

_ Program should include contracts of 25MW for greater consistency with RGGI, CARB. Some exemptions should be made based upon size. (EPUC)

_ Peakers should not necessarily be exempted as that may incent more peakers into the system. (DRA, League of Women Voters)

_ Air Boards won't let more peakers into the system so DRA's concern in moot. Also applying standard to peakers to get additional savings not fair since goal is to prevent backsliding. (PG&E)

_ Including small peakers in an EPS would be administratively challenging. (AReM)

_ In-state, out-of-state, existing, new, and in state renewals of contracts should be included. (Redefining Progress)

_ Repowering needs to be defined. (PG&E)

_ Existing plants should not be included. Only new plants should be part of the program. (SCE)

_ New long-term contracts should be included. (GPI)

_ Concerns raised about additional costs to ratepayers regarding resource adequacy in meeting an interim EPS. (Constellation)

_ If existing contracts covered then concern that IOUs are advantaged over IPPs because they do not enter into contracts with their own generation. (Constellation)

_ If existing plants are grandfathered under the EPS, then risk losing the motivation to retire, repower, or otherwise invest in cleaner resources. (CEC)

_ QFs should be exempt because IOUs are required to take those contracts. In addition, combined heat and power (CHP) should be exempt because of dual use of fuel. Some discussion of a proposal⁶ to calculate emissions from co-generation facilities. (EPUC)

_ Five-year or longer term of contracts should be included as that is consistent with a carbon adder and long-term procurement policies. (PG&E).

_ If standard is 5 years, there is a concern that plants will be contracted for shorter periods in order to bypass the EPS. (UCS).

IV. Standard-setting and Implementation Details Discussion (Day 2)

CPUC staff began Day 2 by moving directly into discussion and shaping of an interim EPS program including definition of the standard, compliance and monitoring, and flexible compliance options. The agenda continued to follow the order of the pre-workshop comment questions.

In the afternoon session, a staff straw proposal was provided for discussion. The straw proposal was further discussed and finessed the following day.

A. Workshop Participant Comments on Standard-setting and Implementation Details

Question 5: What is the standard, and the technical basis for setting it?

Responses to Q5:

_ The standard should be based upon emissions per MW equal to a "well functioning" CCGT. CPUC should coordinate with CEC to determine an appropriate CCGT emissions factor. IGCC plus sequestration should be considered in meeting the standard. (NRDC)

_ Baseload definition could use 60% as cutoff capacity factor, but provisions for reliability issues should be included. (PG&E)

_ Average of CEMS/eGRID data (excluding outliers) could be used as an emissions factor proxy. Alternatively, net system average could also be a solution. (CEC)

_ CEC and NRDC proposals do not address actual emissions due to efficiencies, or lack of, associated with transmission/distribution/locational issues. (IEPA)

_ Need to have a shared definition of CCGT. (Sempra)

_ Objects to "well functioning" as part of the metric proposed by NRDC. SDG&E wants technology to be the standard with multi-attributes for varying technologies. (SDG&E)

_ Baseload renewables should be included. Renewable Energy Credits need to come with purchase, or have emissions factor assigned. Standard should be more aggressive than a CCGT emissions average to meet the Governor's targets. (CRS)

_ More important to determine the goal of the program but don't name specific technology. (EPUC)

_ CCGT should be the standard. (GPI)

_ If a technology based gateway screen is used, then the operational aspects of a plant may be unimportant. Intensity per MWh should be the metric. (CCAR)

_ How to handle repowering of existing plants? (Redefining Progress)

_ One single standard should be used for new and repowered plants. (IEPA)

_ Single standard should be applied to all resources. (GPI, SDG&E)

_ Qualifying facilities should not be included since IOUs are required to take their power. (PG&E)

_ Should use the 95^th percentile standard- best available not just an average standard of existing plants. (Redefining Progress)

_ Standard should be set in a way that avoids gaming and makes sure that unspecified contracts are accurately accounted. (CRS)

_ Should have an R&D exemption to encourage other technologies. (EPUC)

Question 6: How can compliance with the standard be determined?

Participants generally agreed that the CPUC should provide an initial review of baseload contracts eligible for the EPS. Once those contracts are approved, no further review would be necessary. Parties understood that underlying resources might have varying heat rates, that dispatch is beyond an LSE's control, and the interim EPS would be a rough screen. The concept was to implement something in the near-term that would address the primary goals of an EPS.

Key issues to address focused on unspecified resources and repowering of units. The majority of participants agreed that one standard should apply to all resources- as opposed to one standard for new resources, and another for existing and repowered resources. Various proxy options for unspecified resource emission factors were discussed; 1) average emissions from coal generation, 2) WECC average, 3) geographical averages, and 4) CEC's CA net system power average which is the average of the leftover energy in the system that is not claimed- includes in and out of state power, and anything that is not claimed by a CA utility.

Responses to Q6:

_ Operational and dispatch impacts should also be included in the program. (League of Women Voters)

_ System sales should be limited to less than 5 years and therefore would not hit the gateway. (EPUC)

_ No time/duration limit should be imposed upon unspecified resources. (AReM)

_ Unspecified resources are an issue with an EPS and also with a cap. Eventually, we need to deal with it, so we should deal with it now. (GPI)

_ Is there a potential role in assigning a value to unspecified resources using CCAR or some other methodology? (AReM)

_ In a case of "blended" baseload contracts, if one resource does not make it, then the blend should not qualify. (NRDC, Redefining Progress)

_ NRDC's proposal could penalize wind and other renewables. (AReM)

_ If the proposed contract as a whole passes the test, then it should qualify. (Sempra)

_ For unspecified resources, apply emissions factor from the region from which the energy is produced since in most situations it is known where the power is coming from. If average emissions from coal is used as a proxy, it creates a perverse incentive to actually purchase coal. (PG&E )

_ For unspecified resources, average emissions from coal should be the default. (NRDC)

_ SCE is not currently doing any long-term deals for unspecified resources. Not sure that geographical average is the right approach as an LSE might know the delivery point for energy, but doesn't necessarily know what is behind it. (SCE)

_ Renewable power that enters into the system with its Renewable Energy Credits (RECs) assigned to another entity, should not be treated as renewable. Instead, it should be treated as "null" power and assigned a system average of some sort to avoid double counting of renewable attributes. (CRS)

Questions posed by CPUC to parties at this point:

1. Can you "green up" power that would not otherwise qualify?

2. Can you use "null" renewables (renewables that have been stripped of RECs)

_ Don't penalize renewables at this point. We want to encourage as many renewables into the system as we can. We should bring them in as clean, especially since CPUC jurisdictional LSEs cannot currently trade RECs so the double counting issue for them is not significant. (GPI)

_ Null renewable power should not be considered a renewable resource as the renewable attributes have been sold to another entity. (CRS)

Question 7: What compliance and monitoring procedures and monitoring are needed?

Responses to Q7:

_ IOUs are required already to demonstrate compliance to the CPUC. This would be an additional component of the approval process. Once approved, the IOUs' contracts would be considered compliant, and subject to audits and spot checks. (PG&E, Constellation)

_ LSEs could do a simple resource adequacy filing after the fact. Alternatively, they could provide an advance filing to the CPUC signaling their activity. (AReM)

_ As long as the screen is in effect and if all contracts qualify, then no need to do work after the fact. (GPI)

_ Require supply contracts to commit to delivery terms. If it does not happen, then the suppliers are in breach. (IEPA)

_ Might need to check that the plants are running in the way they were supposed to. (Redefining Progress, CCAR)

_ Cogen plants have to show efficiency demonstration to FERC in order to be approved. If things change, they have to be recertified by FERC. Regarding ongoing compliance, if marketer changes mix, they are on the hook financially. (EPUC)

_ Emissions ought to be specified as condition of contract. (NRDC)

Question 8: Flexible compliance options

Responses to Q8:

_ No safety valve needed as long as the screen allows for case by case review. (PG&E)

_ Safety valve may make sense. Want to see offsets as part of a longer term emissions policy, but not sure if needed with interim EPS. (SCE)

_ No offsets should be included in the EPS. (NRDC)

_ Any early action credits should be addressed in Phase II implementation of a load-based cap. (IEPA, NRDC)

_ Sempra's recent experience demonstrates difficulty of using offsets to "clean" energy resources that are large emitters. Their recent attempt to do so was unsuccessful due to concerns about 3^rd party vendors. (Sempra)

_ This program should be coordinated with current bills pending before the CA legislature. (PG&E)

B. Staff Straw Proposal

On the afternoon of Day 2, staff introduced a straw proposal based upon the workshop discussion thus far. That straw proposal, including the modifications made based upon discussion at the workshop, is described below. Discussion of post-workshop comments and an updated staff proposal reflecting comments is addressed in a subsequent section.

1. Design Goals for the EPS

a. Prevent backsliding and commitments that will make future GHG reductions more difficult

b. Minimize costs to ratepayers and minimize the risk of long-term commitments that will raise the cost of future compliance costs

c. Reliability:

i. short-term: do not force shutdown of essential facilities

ii. long-term: consider risks of relying on high emitting resources

d. Administrative simplicity

2. Timeframe

a. Coordinate with procurement proceeding, but adopt now

b. Implement performance standard as interim measure for an unspecified period of time. CPUC will re-evaluate the program when a GHG cap and trade system or other relevant policy (CPUC, state, regional, or other) is functioning.

3. To Which LSEs does the EPS apply?

a. Apply to all jurisdictional LSEs (including ESPs and CCAs)

b. Create ESP process to address ESP procurement related to this program

c. Do not delay pending legislation regarding publicly-owned utilities

d. Develop a filing/approval process for multi-jurisdictional utilities, including a protocol for allocating emissions among resources serving multiple states

4. Program Screens

a. The EPS standard will be applied on a "gateway" basis, at the time a LSE's commitment (build or buy) is proposed.

b. The standard will be applied to the reasonably projected emissions rate from the supply source over the term of the commitment

c. "Covered resources" are resources with a reasonably projected average annual capacity factor of 60% or greater.

5. Which Power Sources are covered?

a. Applied to utility owned new generation, repowering or new/renewal contracts

b. All new and renewal contracts and investments in "covered resources" of five years or longer

c. Applied to baseload and intermediate or "shaping" facilities with annual average capacity factor of 60% or greater

d. Size threshold:

--For specified facilities (built or under contract):

25 MW or greater delivered to the grid;

--For unspecified resource/facilities

under contract: all sizes

e. Application to QFs addressed in legal briefs

f. Self-generation is covered (size threshold determined based on amount delivered to grid; cogeneration thermal load credit calculated, see below).

g. Renewables are covered, emissions factors can be demonstrated at the time of review (includes biomass, waste-to-energy, geothermal, etc.)

h. Reliability exemption considered on a case-by-case basis

6. What is the Standard and How Determined?

a. Emissions standards based upon CCGT performance

i. Higher standard for new facilities : high-performing new CCGT

ii. Moderate standard for existing facilities and repowering - keyed to performance of existing CCGT fleet

iii. Allowance for cogen thermal load

b. Potential R&D exemption on a case-by-case basis (e.g., permit advanced coal facilities that have the capacity to capture and store carbon dioxide "safely and inexpensively" as described in the GHG Performance Standard Policy Statement?).

7. How to apply the standard to units and contracts

a. For single unit specific contracts: applied on facility basis

b. For multi-unit contracts: each covered unit must qualify

c. Baseload renewable product with firming fossil (that qualifies as a "covered resource") -- applied to baseload blend average. If firming unit is unspecific impute appropriate emissions factor.

d. Treatment of null renewable power? Not addressed at this juncture.

e. Unspecified resource contracts: apply appropriate emissions factor. Choices are:

i. WECC system average

ii. Appropriate geographic average (e.g., NW is different from SW)

iii. CEC "Net System Power" calculations

iv. Default to coal emission rates

8. Monitoring and Enforcement

a. CPUC gateway review with documentation and approval required prior to finalizing contract or commitment to construct

9. Offsets, Safety Valves, and other flexibility devices

a. No offsets or market price safety valves

b. Case-by-case "safety valve" upon application and CPUC review for reliability only.

C. Workshop Participants Comments on the Staff Proposal (Days 2 and 3)

_ The proposal should not apply to existing resources. (SCE, PG&E)

_ The goals of the program are not clear. What are the risks that the CPUC is attempting to address? (Constellation)

_ Not sure how this proceeding comports with the procurement proceeding. (SCE, Sempra)

_ Not clear how to address multi-jurisdictional LSEs. (PacifiCorp)

_ How will IOU new generation be addressed? (PG&E, IEPA)

_ Proposal needs to include language relevant to the delivery to the grid to address co-generation produced power. (EPUC)

_ Baseload definition should be more aggressive. (GPI)

_ Projections should be based on an average year. (PG&E)

V. Data Needs (Day 3, continued)

The morning of day three continued the discussion of the staff proposal and modifications as described above. In the early afternoon, the discussion shifted to focus on high-level data that the CPUC needs to assess the essential impacts of an interim EPS. The following list of data was requested after which the workshop concluded. Responses to the assigned data requests are posted at www.cpuc.ca.gov/static/energy/electric/climate+change.

Based upon the responses provided to the service list, staff has made some modifications and updates to the original staff proposal. Specific discussion of findings is included in Section VI below.

At the workshop, the IOUs (PG&E, SDG&E, SCE) and other workshop participants agreed to prepare, and provide to the service list, the information/analysis on topics related to the threshold policy issue and implementation design considerations for an interim EPS, as follows:

1. The size of the potential IOU procurement needs that would be covered by an interim EPS. The IOUs and the CEC are working on a common format for this information and will be providing the format to staff by July 7. By July 11, both redacted (public) and unredacted versions of this information will be provided to staff. The intent is to provide to the service list as much publicly available data on this topic as possible.

2. Analysis around the definition of "covered resources:" What proportion of GHG emissions from long-term commitments would be excluded/included if the threshold for review is 60% average annual capacity factor vs. 50%, 70% or 80%? The IOUs will be providing this information to staff by July 11th.

3. Graph/Schematic of representative heat rates/emission rates for different types of facilities, for the purpose of considering the level of the "moderate" and "high" EPS thresholds for existing/new facilities under the staff Straw Proposal, or alterative approaches. The IOUs and other workshop participants agreed to coordinate on this document, due July 11 to staff.

4. Size of potential ESP procurement. SCE and AReM are working on this information that will be submitted to staff by July 14.

5. Emission factors for unspecified resources. CEC staff will provide the WECC regional emissions average, sub-region averages and the "net system" average figures to staff by July 11.

6. Potential new sources of power (new projects coming on line) proposed for potential sale to California IOUs. CEC, WRA, Constellation and PacifiCorp agreed to pull together the data available on this issue, and provide it to staff by July 11.

In addition, at the workshop several participants agreed to coordinate the development of the following information to present in their post-workshop comments (jointly, if possible):

a. How one would calculate the net emissions rates from renewables (GPI, PG&E, NRDC and others)

b. The formula for a cogeneration thermal credit calculation, and whether it is consistent with the CARB approach: (EPUC circulating to others before comments are due)

c. Protocol for assigning "covered resources" to California for multi-jurisdictional utilities and other implementation issues unique to multi-jurisdictional LSEs (PacifiCorp, WRA).

VI. Comments on the Draft Workshop Report, Staff Discussion and Recommendations

Parties were directed to file comments on the Draft Workshop Report as described in Appendix F. For reference, the revised staff proposal as presented in the Draft Report for comments is included as Appendix H. In addition, Appendix A provides a summary of parties' comments on the revised staff proposal. This section summarizes those comments and identifies key outstanding issues. Each section concludes with a brief summary of staff recommendations on those issues. Rather than attempt to summarize each party's comments in full in this Report, staff will focus on areas of broad agreement, specific debate and/or concern, new recommendations for modification of the staff proposal that were not included in the discussion at the workshop, and other issues of key concern.

Seventeen parties provided comments on September 8, 2006. Those parties are:

_ PG&E

_ SDG&E and Southern California Gas Company (SoCalGas)

_ SCE

_ PacifiCorp

_ Constellation

_ Calpine

_ Independent Energy Producers Association (IEPA)

_ Division of Ratepayer Advocates (DRA)

_ Carson Hydro Project

_ Alliance for Retail Energy Markets (AReM)

_ Western Resource Advocates (WRA)

_ California Cogeneration Council (CCC)

_ Green Power Institute (GPI)

_

_ San Francisco Community Power (SF Power)

_ Cogeneration Association of California and the Energy Producers and Users Coalition (EPUC/CAC, filing jointly)

_ Center for Energy and Economic Development (CEED)

_ NRDC/UCS/TURN/Western Resource Advocates (WRA) (filing jointly)

Key concerns and suggestions are identified below using the questions and format of the directions for post-workshop comments.

A. Threshold Issue: Should the Commission adopt an interim EPS?

Q1 and Q2. Should the Commission adopt an interim EPS? Why or why not? Do you generally support the "gateway" approach to the standard proposed in the revised staff proposal?

Parties' perspectives initially varied significantly on this issue. Several parties supported the interim EPS as described in the staff proposal primarily because 1) it sends a clear signal and regulatory certainty regarding long-term contract requirements, and 2) given the existing procurement requirements, the proposed EPS is unlikely to impose significant burden upon LSEs to comply.

Other parties opposed the concept of an EPS on the grounds that it would largely be largely duplicative of existing CPUC policies such as the Renewable Portfolio Standard (RPS), Energy Efficiency (EE), and the carbon adder. It was unclear if the performance standard would substantively change LSE behavior or the LSE emissions footprint, in which case it seems to be an unnecessary program.

Since enrollment of SB1368 many of the parties who had earlier expressed concerns with the concept of an EPS are now focusing their attention on ensuring that the design of an EPS program addresses their substantive concerns and priorities.

B. Implementation/Design

Q3. Assuming that the Commission decides to proceed with an interim EPS, what should be the major design principles/objectives for such a standard?

Most parties agreed with the priorities included in the revised staff proposal, and provided only minor language modifications. Those priorities are:

1) Prevent backsliding and commitments that will make future GHG reductions more difficult

2) Minimize costs to ratepayers and minimize the risk of long-term commitments that will raise the cost of future compliance⁷

3) Reliability:

i) short-term: do not force shutdown of essential facilities

ii) long-term: consider risks of relying on high emitting resources.

iii) Administrative simplicity, regulatory certainty

Other recommendations included specific provisions for LSEs, encouragement of new technologies, incentives to energy efficiency and renewable energy, minimization of gaming, provisions for allowances for cogeneration facilities. Many of these suggestions did not necessarily fit with the "goals" section and were better suited for consideration in timing and implementation of the program.

SF Power also requested that language be included to assure that the interim EPS will not interfere with development of a load-based cap, and that coordination with regional/international groups could occur. The Commission has made it clear that it is committed to implementing a load-based cap in its Order Instituting Rulemaking Decision and throughout this proceeding, and has stated repeatedly that the interim EPS is meant to support such an effort. In addition, the Commission has stated its support for statewide, regional, and international efforts to address climate change. While both of SF Power's recommendations are foundational elements of climate change policies, staff does not view them to be specific design goals of the EPS.

The issue of consistency with statutory guidelines and requirements was also highlighted. This modification has been included in staff's final proposal below.

In addition, staff wishes to highlight Section 8341(d)(1) which provides a broad overview of the purpose and high-level design of an EPS program.

"On or before February 1, 2007, the commission, through a rulemaking proceeding, and in consultation with the Energy Commission and the State Air Resources Board, shall establish a GHG performance standard for all baseload generation of load-serving entities, at a rate of emissions of greenhouse gases that is no higher than the rate of emissions of GHGs for combined-cycle nature gas baseload generation..."

The revised proposal takes into account parties' recommendations as well as the statutory language in SB 1368, and further recognizes that coordination with the CEC and ARB will also be part of the process of developing and implementing this program.

Q4. Please discuss the relative advantages of the "gateway" approach to an EPS, and the potential disadvantages. If you propose an alternative, please describe.

While not all parties support the concept of an EPS, all parties viewed a gateway screen approach as being the most effective approach if an EPS were to be implemented. No parties proposed an alternative approach to administration of the program.

The principal reasons that parties supported the gateway approach are because it minimizes contract approval uncertainty, sends clear signals regarding compliance, and does not require ongoing administrative oversight and therefore is relatively straightforward to manage. Staff supports a "gateway" standard for these reasons.

Statutory Requirements: The gateway standard proposed by staff and discussed in the workshops is consistent with the language of SB1368, which focuses on LSEs' long-term commitments at the time they are first proposed or entered into:

Section 8341(a) "No load-serving entity or local publicly owned utility may enter into a long-term financial commitment unless any baseload generation supplied under the long-term financial commitment⁸ complies with the greenhouse gases emission performance standard established by the commission, pursuant to subdivision (d), for a load-serving entity..."

8341(b)(1) "The commission shall not approve a long-term financial commitment by an electrical corporation unless any baseload generation supplied under the long-term financial commitment complies with the greenhouse gases emission performance standard established by the commission..."

8341(b)(2) The commission may, in order to enforce the requirements of this section, review any long-term financial commitment proposed to be entered into by an electric service provider, or a community choice aggregator.

Parties provided more detailed recommendations regarding application of a gateway standard and demonstration of compliance. Those recommendations are discussed in more detail in Q18 below.

Q5. The Revised Staff Proposal applies the EPS to new commitments (construction, repowering, and new or renewal contracts). Please comment on whether you support the Proposal on this issue, indicating your views on the relative advantages and disadvantages of applying the EPS to both new and existing generation facilities (under new commitments). Relate your response to this question to the design priorities you articulate under question #3 above.

In post-workshop comments submitted prior to enrollment of SB1368, many parties argued that the EPS should apply to new commitments with new facilities only. Others agreed it should apply to "new" facilities but also included repowered facilities as "new" and therefore subject to the EPS. Under this approach, resources currently under contract with an LSE would not be subject to the EPS, even if that contract was to come up for renewal while the EPS is in place. Most of these parties argued that if the CPUC is most concerned with preventing "backsliding" on emissions prior to a cap being implemented, then existing resources should not be subject to the EPS as they are part of the status quo.

A third group of parties argued that all new commitments, including renewal of existing contracts as well as new construction, repowering, and new contracts should be subject to the EPS. Since the EPS is administered on a contract by contract basis using the gateway approach, it is not prudent for the CPUC to "grandfather" in any resources under current contract that would be subject to renewal during the EPS. The Rule should not create an incentive for LSEs to renew existing contracts, rather than making resource decisions based upon the broad portfolio of all available resources. An artificial incentive to renew existing entitlements could arise if the EPS were limited in scope to new resources only.

SB 1368 provides direction as to which resources are to be covered. As indicated above, the definition of "long-term commitment" includes new ownership investment in baseload generation or a new or renewed contract with a term of five years or more. Sections 8341(a) and (b) require that the Commission approve only utility long-term financial commitments that comport with the EPS program and also expressly grants the commission the authority to "review any long-term commitment proposed to be entered into by an energy service provider or community choice provider.

Section 8341(d)(1) also states that "... All combined-cycle natural gas powerplants that are in operation, or that have an Energy Commission final permit decision to operate as of June 30, 2007, shall be deemed to be in compliance with the greenhouse gases emission performance standard."

Staff recommends that all new or renewal contracts and/or commitments with resources, including existing, repowered, and new facilities, be subject to the EPS. For the purposes of ensuring that existing contracts and investments are not required to be renegotiated, all facilities that meet the requirements of Section 8341(d)(1) should be deemed in compliance at the onset of the EPS program. As contract renewals and/or repowering of those facilities occur, they should be subject to the gateway standard. The decision to renew a contract or repower generation commits California's LSEs and ratepayers to those costs and emissions profiles just like a decision to enter into a new contract with a new facility.

Q6. Should the EPS cover only commitments (construction or contracts) of five years or longer as the workshop participants generally agreed? There was also general agreement among workshop participants that if adopted, an interim EPS should cover commitments (construction or contracts) five years or longer, which is also reflected in the Staff Straw Proposal. Do you agree? Why or why not? How does this design parameter achieve (or not achieve) the priorities you have identified under question #3 above?

All of the parties except for DRA supported the five year or longer commitment cutoff as it comports with the CPUC current long-term procurement plans and with the spirit of the CPUC's Performance Standard Policy Statement.

DRA proposed inclusion of short-term contracts (and contracts smaller than 25MW) as peaking and shaping resources are often higher emitting than baseload resources.

Staff has been directed to recommend an interim program that can be implemented in the near-term. Discussion at the workshop, including that of CPUC staff assigned to procurement activities, and subsequent comment by the majority of parties indicates that inclusion of short-term contracts would be burdensome to manage in the near-term and could raise reliability issues as well. The proposed inclusion of contracts of five years or greater avoids long-term commitments to high-emitting resources, and provides the clearest path to implementation while mitigating reliability issues associated with peak and seasonal demand.

SB 1368 largely lays to rest this debate as Section 8340(j) provides the definition as follows: "`Long-term financial commitment' means either a new ownership investment in baseload generation or a new or renewed contract with a term of five or more years, which includes procurement of baseload generation."

Based upon the statute, and consistent with the majority of parties' views, staff continues to recommend that the EPS cover commitments (construction or contracts) of five years or longer.

Q7.  Another major design issue discussed at workshops was what the Commission should look at (contract or facility operation) in determining whether the EPS applies.  In particular, should the Commission (1) look at the operation of the facility underlying a contract, or (2) only to the amount/product contracted for by the LSE?  The Staff Proposal takes the approach that, for specified contracts, the Commission should look at the expected operation and emissions of the facility, rather than just the contracted amount.  Please comment on the advantages and disadvantages of these two alternative approaches, and your position on this issue.

Specified Commitments:

For specified contracts and commitments, several arguments emerged.  PG&E argued that the screen should be applied to the resources procured under the contracts and not the entire facility or facilities that happen to be owned by the contracting party.  SDG&E/SoCalGas, SCE, and Constellation further argued that it would be burdensome to identify the operations of the underlying resource. 

Alternatively, other parties supported inclusion of facility operations as part of the gateway review.  PacifiCorp and IEPA recommended that the facility's average emission rate be used as the appropriate emissions factor in the case of specified contracts. 

Calpine, DRA, NRDC/TURN/UCS supported review of the underlying facility as well. 

DRA and GPI also recommended that the definition of baseload generation be modified to include powerplants operating at a capacity factor of 50% or greater.

The revised staff proposal recommended that specified long-term contracts and commitments of 25MW or greater delivered to the grid with a capacity factor of 60% or greater be required to go through the gateway screen.  At that point, the emissions factor for the underlying facilities would be applied.

SB1368 offers guidance on the definitions of baseload generation, long-term financial commitment, and capacity factors.

Section 8340(a) specifies that "`Baseload generation' means electricity generation from a powerplant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60 percent."

Section 8340(j): " `Long-term financial commitment' means either a new ownership investment in baseload generation or a new or renewed contract with a term of five or more years, which includes procurement of baseload generation."

Section 8341(b)(4) states, "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, as determined by the commission based upon the electricity purchase contract, any certification received from the Energy Commission, any other permit or certificate necessary for the operation of the powerplant, including a certificate of public convenience and necessity, any procurement approval decision for the load-serving entity, and any other matter the commission determines is relevant under the circumstances."

Regarding the overall purpose of an EPS, Section 8341(d) states, "On or before February 1, 2007, the commission, through a rulemaking proceeding, and in consultation with the energy Commission and the State Air Resources Board, shall establish a greenhouse gases emission performance standard for all baseload generation of load-serving entities, at a rate of emissions of greenhouse gases that is no higher than the rate of emissions of greenhouse gases for combined-cycle natural gas baseload generation.

The statutory language is prescriptive in its preference for an annualized capacity factor of 60 percent or greater, and does not provide provisions to reduce the percentage that is used in defining baseload generation.

The language does offer flexibility regarding the methods and documentation used to determine in calculating the capacity factor for the commitment. Parties have identified two primary options in determining the capacity factor attributable to an LSE's commitment: 1) evaluate the commitment based upon the LSE's intended use of the powerplant, or 2) evaluate the commitment based upon the design and intended use of the underlying powerplant itself.

The overall purpose of the EPS is encapsulated in Section(d)(1) with the commission being required to "establish a greenhouse gases emission performance standard for all baseload generation of load-serving entities."

Based upon discussion at the workshop, comments submitted by parties, and the provisions of SB 1368, staff recommends that in the case of contracts, or other commitments with specified facilities, the annualized capacity factor of the underlying resource, rather than the size of the LSE commitment, should be used in determining whether the gateway screen applies. SB 1368 is clear is establishing its interest in ensuring that LSEs do not enter into contracts with baseload facilities whose emissions are higher than combined cycle natural gas powerplants designed and intended for baseload operations.

NRDC/TURN/UCS/WRA presented persuasive arguments regarding the intent of the legislation in providing their arguments in support of underlying resource review. For specified contracts, the capacity factor, average heat rate, and emissions factor of the underlying facility(s) supplying power should be readily available as operators are required to provide this information to multiple regulatory agencies such as the US EPA and CA Air Districts. 

Constellation and EPUC/CAC express concern that under the revised staff proposal Utility Retained Generation (URGs) would not be subject to the EPS. PG&E argues that only changes to a powerplant that result in a net increase of the rated capacity of the plant be considered as changing the status of the facility from being deemed in compliance to being required to demonstrate compliance. NRDC/TURN/UCS/WRA recommend that URGs that undergo major renovations be covered under the cap.

Staff accepts NRDC/TURN/UCS/WRA's proposal on this point. Major renovations of existing facilities, like other major financial commitments, involve long-term commitments that will affect power costs, environmental impacts, and ratepayer interests for many years. As the nation has learned with respect to "new source" standards under the Clean Air Act, extensive renovation does not necessarily require expansion, but it does implicate long-term emissions trends. Including such events in the definition of long-term commitments is reasonable and comports with the definition of baseload generation as defined in Section 8340(a).

Based upon discussion at the workshop and post-workshop comments filed, staff recommends that the underlying resource's annualized operations and emissions profile be used in determining whether the gateway screen is triggered. For specified contracts, the capacity factor, average heat rate, and emissions factor of the underlying facility(s) supplying power should be readily available as operators are required to provide this information to multiple regulatory agencies such as the US EPA and CA Air Districts. 

Unspecified contracts:

For unspecified contracts, the IOUs argue that the requirement to include information about an underlying facility's operation would be administratively burdensome, and in many cases impossible, as the facility or facilities under contract would either not be known or facility operations would be proprietary information and not likely to be disclosed to a contracting LSE.  LS Power and Constellation believe that only new resources should be included in the EPS in order to simplify the reporting process.

PacifiCorp argues that unspecified contracts should be required to have an emissions rate imputed on a MWh basis. Other parties (NRDC/TURN/UCS/WRA, DRA) support looking at the underlying resource in order to ensure that LSEs are not entering small contracts with large high emitting baseload resources, and to limit gaming of the system based upon size of contract.

Based upon parties' comments, it is evident that it would be burdensome and in many cases infeasible to estimate the operations of unspecified facilities. The staff proposal recommends review of unspecified contracts based upon the size of the commitment, rather than the specific emissions profile of the underlying facility as it is understood to be unknown. In cases where it is known that the underlying facility's capacity factor is less than 60%, the gateway screen would not apply. If the capacity factor is either unknown, or known to be 60% or greater, the gateway screen would apply. For unspecified contracts, an appropriate emissions factor would be imputed, from the best available information, as discussed at Q 15 below.

However, staff does recognize the potential gaming issues raised by DRA and NRDC/TURN/UCS/WRA and makes the following recommendation under "All commitments" below to address potential "slicing and dicing" of contracts, or other evasive procurement activities that may be undertaken to avoid an EPS screen. In addition, to the extent possible, staff encourages LSEs to enter into specified contracts.

On the subject of treatment of unspecified power, SB 1368 offers the following in Section 8341(d)(7): "In developing and implementing the greenhouse gases emission performance standard, the commission shall address long-term purchases of electricity from unspecified sources in a manner consistent with this chapter."

All commitments (specified and unspecified):

The focus of the interim EPS program is on power supply reliance and financial commitments by California LSEs for baseload resources. By limiting inclusion of covered resources to LSE commitments of 25MW or greater, staff intends to reduce the administrative burden of compliance with an EPS, and to focus attention on LSE's long-term baseload commitments rather than peaking or shaping activities required for reliability. Thus, we recommend that the 25 MW threshold apply to the contract or other commitment made by a LSE.

At the same time, the Rule should not create incentives for LSEs to avoid the substantive standard simply through contractual "gaming" - that is, by entering into multiple smaller contracts, each of which may be below the jurisdictional thresholds, but which together amount to a significant long-term commitment of LSE resources. To that end, staff recommends that a series of related contracts with the same supplier, likely resource, or known facility, or a series of related or similar contracts with separate sources should be considered as a single commitment in size, capacity factor, and duration.⁹

Such multiple contract activities must be disclosed by the utilities to the CPUC in order to avoid "slicing and dicing" of large contracts to avoid or manipulate the gateway screening process for the performance standard review. Utilities that do not disclose such activities will be considered in violation of the performance and subject to penalty and enforcement mechanisms.

NRDC/TURN/UCS/WRA raise concerns about this approach to ensure contract gaming does not occur. They are specifically concerned that it is administratively burdensome. Instead they recommend that all LSE contracts of 5 MW that have an underlying resource operating at an annualized capacity factor of 60 percent or greater be covered by the gateway screen. By using this approach, after the fact review regarding contract gaming via "slicing and dicing" would not be necessary.

Staff sees the merit in this approach, but does not view it to be reasonable given the implementation timeframe for the program and the upfront administrative burden that would be required for compliance. Rather, staff is inclined to focus on larger contracts as consistent with current long-term procurement processes and data available, and to make further modifications and improvements to the program as the program matures as consistent with Section 8341(b)(3), "The commission shall adopt rules to enforce the requirements of this section, for load-serving entities. The commission shall adopt procedures, for all load-serving entities to verify the emissions of greenhouse gases from any baseload generation supplied under a contract subject to the greenhouse gases emission performance standard to ensure compliance with the standard."

We recognize that some professional judgment is required to determine when certain contractual commitments are "related" or "similar" so as to trigger review as a single commitment. However this is a common enough problem in environmental regulation and utility prior review programs, and we expect a professional rule of reasonableness to govern its application here. LSEs that are in doubt as to the application of the Rule to new long-term commitments can disclose their contracting patterns to the Commission and seek a jurisdictional determination under the Rule.

Q8.  There was general agreement during the workshop that an interim EPS should not apply to peaking facilities or resources expected to operate relatively few hours during the year.  Accordingly, the Staff Straw Proposal uses a definition for "covered resources" as those with an annual average capacity factor of 60% or greater, intending to cover resources operating as year-round base load and high-use intermediate and shaping facilities.  Do you believe that this definition of covered resources is appropriate?  In responding, please address the following:

a. What types of resources do you believe the EPS should cover and whether you believe the straw proposal capacity factor (60% or greater) metric to define a covered resource will capture those resources.

Most parties recommended that the EPS cover all baseload resources defined as those resources with a 60% or greater capacity factor (c.f.). Parties that supported a 60% c.f. referenced data submitted by the IOUs in responses to data questions 1 and 2 ("Size of potential IOU procurement needs that would be covered by an EPS" and "Portion of GHG emissions from long-term commitments that would be included at various capacity factors"). Data submitted for questions 1 and 2 illustrated that a 60% c.f. captures 78% of the IOUs' 2012 open procurement need and would capture 72% of CO2 emissions.

Lowering the threshold capacity factor to 40-50%, (as suggested by GPI and DRA) would result in additional emissions captured, but these reductions would not be as significant as the incremental step-down from 70% c.f. to 60% c.f., which represents the largest delta with regards to emissions reductions at the different capacity factors. For example, a 50% capacity factor would affect an additional 5% of procurement and capture an additional 6% of CO2 emissions. Comparatively, the move from 70% c.f. to 60% c.f. affects an additional 13% of procurement and captures 13% more emissions.

Based on the data and comments, staff recommends a 60% capacity factor as a reasonable threshold and one that comports with the requirements of Section 8340(a). This approach captures the large majority of emissions from potentially emitting resources, while minimizing administrative burdens and potential interference with resources needed to meet peak loads.

b.  Present an alternative metric(s) for defining "covered resources" that you recommend, if you do not support the Staff Straw Proposal definition. 

GPI and DRA advocated for a lower than 60% capacity factor (40%-50%) to ensure that all high emitting intermediate and shaping facilities are covered.

See discussion and staff recommendation above (Q8.a.)

c. Whether (and if so, how) the EPS should incorporate a research and development exemption for advanced coal or other technologies.

Some parties suggested an R&D exemption for advanced coal technologies and specifically one for IGCC carbon capture-ready technology (SCE, PacifiCorp). SDG&E suggested a more general, non-technology specific R&D exemption that could be applied on a case-by-case basis. Other parties argued that no exemptions should be granted and that all resources should be required to meet the EPS (Calpine, DRA, NRDC, TURN, UCS, GPI).

Based on parties' comments, staff recommends a R&D exemption that could be granted by the CPUC on a case-by-case basis for higher-emitting facilities upon demonstration that the commitment in question will make a significant contribution to developing a lower-emitting resource mix in the future. One example might be an advanced coal facility that has an equal or better emission rate than the estimated IGCC average heat rate and emissions, and that has or will have within a reasonable period of time the capacity and an existing plan to capture and store carbon dioxide as described in the GHG Performance Standard Policy Statement.

In addition, in the case of powerplants that have implemented geologic carbon sequestration technology, staff recommends that the sequestered CO2 be excluded from the emissions calculation for that facility as consistent with Section 8341(d)(5):

"Carbon dioxide that is injected in geological formations, so as to prevent releases into the atmosphere, in compliance with applicable laws and regulations shall not be counted as emissions of the powerplant in determining compliance with the greenhouse gases emissions performance standard."

Q9. Another design issue discussed at the workshop was how the EPS should apply to specified contracts with more than one underlying covered resource (new or existing): Should the Commission apply the EPS to the "blend" of the resources/units, or require that each covered resource meet the EPS individually?

Under the Staff Revised Proposal, each individual covered resource must meet the EPS, with the exception of a renewable contract firmed with a non-renewable resource. In that case, the blend of the two must meet the EPS, rather than the individual resources/units.

Do you agree with this approach? Why or why not? In your response, present your view of the relative advantages and disadvantages of the alternate approaches, and discuss your recommendation in the context of your answer on design priorities under Question #3.

Many parties supported the staff proposal recommendation. However, a language nuance was raised by several parties. The staff proposal requires each covered resource to be in compliance with an EPS. Parties communicated difficulty in determining the activities of specific units that may be operating at a multi-unit facility or plant. SDG&E suggests in these cases to use the information available at the plant level, and to allow for exceptions where necessary.

Regarding renewable power firmed with a non-renewable resource, PG&E felt strongly that any RPS eligible resource, regardless of any associated firming resources, should be deemed in compliance with the EPS.

GPI recommended clarification language regarding determination of the capacity factor for renewables firmed with fossil resources. They suggest that the combined annual capacity factor of the resources be used in determining whether the screen applies or not. Staff supports this recommendation.

For contracts with multi-unit powerplants where contracts where specific unit operations are unknown, staff recommends modifying the proposal to allow for facility/plant average as SDG&E suggests.  In the case of renewables with covered firming resources, staff recommends no change to the revised proposal-- the resource blend must meet the EPS.  Staff recognizes that the California Energy Commission (CEC) sets eligibility rules for generation resources that can counted toward the Renewables Portfolio Standard (RPS).  Pursuant to SB 107 (Simitian), CEC must develop criteria for RPS eligibility of shaped and firmed renewable generation. Staff recommends that this Commission continue to coordinate with the CEC to ensure consistency in these matters.

Q10. In the context of the Staff Revised Proposal, how should the Commission treat partial contracts under the proposed EPS? An example discussed at the workshop was a "summer product" contract for power from a specified coal plant. For partial contracts, should the Commission look at how the facility is operating during the duration of the contract commitment, at the MWhs being purchased relative to the full year of facility operations, or consider other approaches? Would your proposed treatment of partial contracts result in an exemption under the 60% capacity factor rule, even if that underlying facility would be a "covered resource" under average annual operation? Why or why not?

Most parties recommend that, similar to Q7, the contract be subject to the EPS rather than the underlying facility. Many parties expressed concern about inclusion of short-term shaping resources in the EPS, as these resources are required for seasonal reliability and are not baseload resources.

NRDC/TURN/UCS supports inclusion of these contracts on the basis of the underlying resource.

Staff recommends that partial-year contracts for shaping resources that have less than a 60% annualized capacity factor not be covered by the EPS because of the seasonal reliability issues that they address. It is important to note that this distinction is based upon the size and expected capacity factor of the commitment (and thus its GHG emissions), not its name or degree of dispatchability.¹⁰ However, the multiple contract provisions discussed above in Q7 would apply. LSEs are not allowed to enter into multiple small or shaping contracts in order to avoid the EPS gateway screen.

Q11. The Staff Straw Proposal allows for an exemption from the standard for specified units of 25 MW or smaller, based on the size of the facility under construction or providing power under a contract. However, there would be no size exemption for unspecified contracts of any size. In commenting on this aspect of the Straw Proposal, please address the following:

a) The MW level of the "small unit" exemption under this proposal. Do you support this exemption as proposed? Would you propose a different size exemption level and/or one specifically tied to projects qualifying under the self-generation incentives program? No exemption? Why or why not?

The majority of parties supported inclusion of resources 25MW and greater for specified units, on the basis of current long-term contract requirements, compatibility with the Air Districts and US EPA regulations, and because it comports with the Northeastern Regional Greenhouse Gas Initiative (RGGI) emissions cap program.

In addition, many parties argued that all contracts, including unspecified, be subject to the 25MW or greater threshold in order to maintain consistency and to minimize administrative complexity (PG&E, SCE, SDG&E, IEPAA, CCC, EPAC, CAC).

NRDC/TURN/UCS, DRA, and in some cases GPI, support a 5MW cutoff for compatibility with the self-generation incentive program (SGIP), and to ensure inclusion of high emitting resources associated with small contracts. Further NRDC/TURN/UCS suggests that no size exemption be given for unspecified contracts since it is impossible to identify the resources behind these contracts.

Staff recommends no change to the current proposal for specified contracts, as it is not persuaded that significant benefits would result from lowering the size threshold for review.

For unspecified contracts, staff recommends a 25MW or greater threshold for contracts and commitments for the screening process in order to focus on long-term contracts, create consistency, and mitigate administrative complexity across the screening process. Parties did not present persuasive arguments to support a requirement that all unspecified contracts should go through the screening process.

The interim EPS is meant to be implemented in the near-term and mitigate administrative complexity where possible. Being that the program is intended to focus on long-term baseload contracts, and we are adding provisions for multiple contracts to prevent "slicing and dicing" of contracts, staff recommends that 25MW be the cutoff for both specified and unspecified commitments as it is most consistent with current Commission, state, and other jurisdiction's emissions policies.

b) Basing the exemption on MWs delivered to the grid. In determining eligibility for the size exemption, the Staff Revised Proposal would subtract out self-generated power that was not delivered to the grid.

i) Please indicate whether you agree with this approach to determining the size exemption, why or why not?

ii) If the Commission adopts this approach, what type of information (and source of data) would need to be presented for the Commission to determine the amount of expected self-generation to subtract from the unit size?

The majority of parties commenting on this matter support the staff proposal, and the calculation proposed for crediting cogeneration facilities.

NRDC/TURN/UCS/WRA suggest that the EPS apply to all of the emissions associated with a LSE's contracts, even if the energy is used on-site as GHGs are emitted either way. However, where the electrical output retained on-site by a customer is not part of the LSE's financial commitment or acquisition, we cannot conclude that it falls within either the commission's purposes in establishing the EPS, or the definition of covered resources in AB 1368. Thus, the Revised Staff Proposal continues to focus on the size of the resources delivered to the grid or otherwise made a part of the LSE's portfolio.

With respect to the calculation of emission rates at co-generation facilities, Staff recommends adoption of the methodology proposed by EPUC/CAC. This method is consistent with Section 8341(d)(3), which requires the commission to establish an output-based methodology to ensure that the calculation of emissions of greenhouse gases for cogeneration recognizes the total usable energy output of the process, and includes all greenhouse gases emitted by the facility in the production of both electrical and thermal energy.

Staff recommends use of the cogeneration "methodology" put forward by EPUC/CAC and supported by CCC as an interim recommendation for the purpose of meeting the implementation deadline of February 1, 2007 as required in Section 8341(d)(1) and compliance with Section(d)(3). This calculation could be modified in the future if the Commission deems it necessary. Staff also notes that for the purposes of consistency, all electricity delivered to the grid by a cogeneration facility is subject to the gateway screen as with other specified resources delivering electricity to the grid. During the "gateway screening process" this methodology still requires a case by case evaluation, because the data used to make the calculation will be different for every plant.

Section 8341(d)(3) states "The commission shall establish an output-based methodology to ensure that the calculation of emissions of greenhouse gases for cogeneration recognizes the total usable energy output of the process, and includes all greenhouse gases emitted by the facility in the production of both electrical and thermal energy.

c) Basing the exemption on the size of the unit being constructed or underlying a unit-specified contract, rather than the size of the contract. Please discuss the relative advantages and disadvantages of these alternate approaches to a size exemption, and indicate which you would recommend, should the Commission determine that a size exemption would be appropriate. (You may refer to your answer to the related Question 7, as appropriate).

As discussed in Q7 and Q11a, after review of the comments, staff recommends that specified long-term contracts and commitments of 25MW or greater delivered to the grid be required to go through the gateway screen. The screen would apply to the committed underlying resource and its average emissions factor. For unspecified contracts, staff recommends the emissions factor for unspecified contracts be imputed based upon the contract size rather than attempting to identify the emission rates of the underlying facility or facilities. We realize that a more detailed emissions tracking system will be of great use to LSEs in the context of a load-based cap-and-trade system, but are persuaded that individual facility emissions rates may not be readily available to LSEs for unspecified contracts at this time.

For specified contracts, DRA and NRDC/TURN/UCS arguments to lower the size threshold did not substantiate the benefits to doing so. The vast majority of commenting parties supported the 25MW or greater threshold as it comports with current CPUC, state, federal, and regional emissions policies, and comports with the interim EPS focus on baseload resources.

For unspecified contracts, parties persuasively argued that information about underlying resources would be difficult, if not impossible, to ascertain at the present time. Because of this administrative impediment, staff recommended in Q7 to modify the unspecified rule to trigger the gateway screen.

d) No size exemption for any unspecified contracts. Do you support this approach? Why or why not?

Most parties did not comment on this issue. SCE recommends the same size exemption for specified and unspecified contracts¹¹. LS Power believes that it is unlikely that new non-unit specific contracts will be entered into during the period of the interim EPS, so views this as a non-issue. IEPA believes that no exemptions should be made for unspecified contracts. NRDC/TURN/UCS supports the staff proposal recommendation to require all long-term unspecified contracts of any size to be covered by the EPS.

For the reasons discussed above (see discussion at Q7), staff recommends that the EPS apply to the size of the commitment involved rather than to the size of the underlying facility or facilities that may be supporting the contract. We recommend setting the size exemption for unspecified contracts at the same level as for commitments with specified facilities (i.e. 25MWs or greater). If the EPS is designed to look at the emissions associated with a contract or commitment, then it is reasonable, and easier to administer, if the size of contract covered under the EPS is the same for both specified and unspecified resources. Provisions to aggregate multiple contracts will be needed in order to avoid contract gaming for jurisdictional purposes (see discussion at Q7).

Q12.   Under the Initial Staff Straw Proposal, the Commission would develop two separate standards for covered resources:  1) a "moderate" EPS to apply to existing resources and repowering and 2) a "high" EPS to apply to new resources.  Both would be based on the performance of a combined-cycle gas turbine (CCGT).  Please address the following questions in your comments on this approach:

a.         Do you agree in concept with a dual standard as outlined in the Staff Straw Proposal, why or why not?

b.         If the Commission adopted this approach, what performance standard do you recommend for the "moderate" and "high" EPS?  Express your answer in terms of heat rates as a proxy for GHG emission rates.  Explain why you chose these levels, and the source of data/calculations you used to develop them.

c.         If instead you recommend a single EPS based on the performance of a CCGT for all new commitments (whether to new resources, existing or repowered facilities), provide your recommended performance standard (expressed as a heat rate), explain why you chose this level, and the source of data/calculations you used to develop it.

d.         In responding to b. and c. above, be specific as to how you developed your CCGT reference standard and the data sources/calculations used.  For example, did you base it on the expected performance of a modern CCGT newly placed in service, or at the end of its useful life, or an average of emissions from existing CCGTs, or another approach? 

e.         If you have alternate or additional recommendations for the EPS standard and calculation, please submit them.

Data submitted by a working group composed of the IOUs and other parties in response to data question 3: "What are the representative heat rates/emission rates for different types of facilities?" provided the background for parties' responses to Q12. The first worksheet, "Heat rate and emissions w/vintages," shows that emissions for those CCGT plants built from 1980 to present range from 800-1020 lbs CO2 / MWh. Within this range, there are no significant difference among vintages. In contrast, for other types of gas plants, such as single turbine, the range extends upwards to 1250 lbs CO2/MWh.

Since both existing and new CCGTs perform at nearly the same levels, and since there are strong economic incentives for new gas facilities to perform efficiently, staff concludes that it is not necessary to impose a stringent standard for "new" facilities as opposed to existing units. New or repowered CCGT plants are likely to have a low emissions profile in order to be competitive. Most parties suggested one EPS standard instead of a moderate and high standard. Two reasons were given: administrative ease (LS Power, Constellation) and the ability of one standard to sufficiently incorporate all existing CCGT plants while discouraging less clean facilities (NRDC/TURN/UCS).

Based upon comments and the data presented, staff does not see the need for two EPS standards.

The second worksheet, "Spreadsheet of existing emissions rates" provides emissions data from EPA's Continuous Emissions Monitoring System (CEMS) on existing CA gas plants. This spreadsheet details that the range of emissions from CA gas plants operating at 60% capacity factor or greater is between 794 and 1,006 lbs CO2/MWh with an average of 856 lbs CO2/MWh.

Multiple parties proposed 1,100 lbs CO2/MWh as the single standard (SDG&E, NRDC/TURN/UCS, GPI). SCE proposed a high standard of 1,000 lbs CO2/MWh and a moderate standard of 1,400 lbs CO2/MWh.

After consideration of the data and suggestions proposed by parties, in the Revised Staff Report, staff recommended a single standard, applicable to new and existing plants and contracts, of 1,000 lbs CO2/MWh. This standard allows for high performing existing CCGTs to qualify and is significantly above the average emissions reported for gas plants within and outside of the state.

The majority of parties commenting on the Revised Staff Report's recommendation of 1,000 lbs CO2/MWh were opposed (PG&E, SDG&E/SoCalGas, SCE, GPI). Most of these parties recommended a value of 1,100 lbs CO2/MWh as being most reflective and inclusive of the current CCGT fleet and consistent with Section 8341(d)(1) which requires the emissions performance standard "to be no higher than the rate of emissions of greenhouse gases for combined-cycle natural gas baseload generation."

Some parties (NRDC/TURN/UCS/WRA, Calpine, and DRA) supported setting the standard at 1000 lbs CO2/MWh as it would encourage operations of, and investments in , the cleanest CCGT facilities and technologies.

One party, SF Community Power, argued for a standard that would focus on coal resources specifically and suggested that the Commission should not approve procurement from a coal plant with average net emissions greater than a supercritical steam turbine coal-fired plant, or based upon a MWh emissions rate from an inefficient California-based gas-fired steam plant.

Staff rejects SF Community Power's arguments as we view them to be in conflict with Commission's GHG Policy Statement and with SB1368. In the October 6, 2005 GHG Policy Statement, the Commission describes a GHG emissions performance standard that would limit the GHG emissions levels for all new utility-owned generation and all long-term procurement contracts to "no higher than the GHG emissions levels of a combined-cycle natural gas turbine." Staff does not see the merits of expressly excluding a resource based upon fuel type or geographic location. The EPS as currently contemplated is anticipated to include all new and renewed LSE sources and contracts for power subject to the gateway standard regardless of resource type or location.

Further, staff does not believe this recommendation comports with Section 8341(d).

Based upon parties' comments on the Draft Staff Workshop Report and in light of the passage of SB 1368, staff recommends modifying the acceptable emissions rate for the single standard to be 1100 lbs CO2/MWh.

In addition, staff reiterates the recommendation regarding Q5 above: Staff recommends that all new or renewal contracts and/or commitments with resources, including existing, repowered, and new facilities, be subject to the EPS. For the purposes of ensuring that existing contracts and investments are not required to be renegotiated, all facilities that meet the requirements of Section 8341(d)(1) should be deemed in compliance at the onset of the EPS program. As contract renewals and/or repowering of those facilities occur, they should be subject to the gateway standard. The decision to renew a contract or repower generation commits California's LSEs and ratepayers to those costs and emissions profiles just as a decision to enter into a new contract with a new facility.

Q13.  There was general agreement at the workshop that the Commission should allow credit for cogeneration thermal load when applying the EPS to covered resources.  This is reflected in the Staff Straw Proposal.  Do you agree with this approach, why or why not?

If you have developed a specific formula for the calculation of such a credit, please provide it in an attachment to your post-workshop comments, or in a separate joint submittal at the same time (if you are joining in with other parties on this issue).  Indicate whether it is consistent with methods used to credit thermal loads in other emissions regulations for cogeneration facilities, either in California or elsewhere. 

As part of the post-workshop data requests, EPUC/CAC submitted the following formula¹² for calculation of a revised emissions rate for cogen facilities that reflects credit for useful thermal energy: Emission Rate = Total GHG Emissions / kWh of Electricity + Btu Thermal Energy (converted to kWh). This calculation was also supported by CCC and DRA.

Concerns were expressed by some parties that the above calculation overstates useful thermal energy. Alternatives to the calculation include:

1. Apply a discount factor such as 50% to the formula to correct for the assumption that all thermal energy is convertible to electricity (SCE);

2. On a case-by-case basis, assume thermal application separate from electricity production by calculating CO2 savings from avoided boiler use (assuming 80% boiler efficiency) and subtracting saved lbs CO2 / kWh from standard facility lbs CO2 /kWh.

3. Although not providing a specific alternative, NRDC/TURN/UCS advocated for a methodology to be applied on a case-by-case basis that accounts for useful, and not only theoretical thermal energy.

Staff recommends the cogeneration methodology put forward by EPUC/CAC and supported by CCC as an interim recommendation for the purpose of meeting the implementation deadline of February 1, 2007 as required in Section 8341(d)(1). This calculation could be modified in the future if the Commission deems it necessary. During the "gateway screening process" this methodology still requires a case by case evaluation, because the data used to make the calculation will be different for every plant.

Q14.   Do you have a position on how to calculate the net emission rates from renewables (e.g., for waste-to-energy, geothermal resources) for the purpose of applying the EPS?  If so, please present your views either in your individual post-workshop comments or jointly with other interested parties at the same time.  

Most parties commenting suggested assigning a zero emissions rates for all renewables, including those from biogenic sources (PGE, SDG&E, DRA, GPI, IEPA). NRDC/TURN/UCS/WRA suggested net emissions be considered for biogenics and zero emissions rate for other renewables, and also recommended that the Report clarify that commitments for renewable resources be required to go to the gateway and not be deemed exempt resources.

The rationale provided by GPI in its recommendation for assignment of zero emissions to all renewables including biogenics, is that although biogenic renewables (biomass and biogas generators) have higher GHG emissions from the stack than CCGT, when net emissions are properly accounted for, these resources reduce the net emissions associated with the alternative disposal of these same materials and eventually have lower emissions than CCGT plants.

Section 8341(d)(4) states, "In calculating the emissions of greenhouse gases by facilities generating electricity from biomass, biogas, or landfill gas energy, the commission shall consider net emissions from the process of growing, processing, and generating the electricity from the fuel source."

Based on parties' comments and the statutory language above, staff recommends that long-term baseload contracts and commitments with renewable resources be covered by the EPS. As any resource, these commitments should appear at the gate and file their applicable net emissions rate. Resources identified in Section 8341(d)(4) shall include their emissions estimates in manner compliant with that section. Staff supports NRDC/TURN/UCS/WRA's clarification that baseload commitments for renewable resources are not exempt from the EPS.

Q15.  There was discussion during the workshop on how to address unspecified contracts, i.e., what imputed emissions factor to use.  The following alternatives were identified:

a.         Western Energy Coordinating Council (WECC) system average;

b.         Appropriate geographic average (e.g., Northwest purchases represent different resources than purchases from the Southwest);

c.         California Energy Commission (CEC) "Net System Power" calculations;

d.         Default to coal emission rates.

Please discuss your recommended approach, and why.  Be as specific as possible as to the source of the data (or specific numbers) you would use for this purpose.

The CEC provided data on the underlying fuel mix for imputation factors(a)-(c) above. Emissions rates for (d). (coal) were provided as part of the emissions data in data question 3. Although imputed emissions rates were not provided for these options per se, the provision of the underlying fuel mix sheds sufficient light on whether such an emissions rate would pass a CCGT-based EPS.

Parties had varying opinions on the appropriate imputed emissions factor. PG&E advocated for a geographic average that would distinguish among WECC sub-regions. SDG&E, PacifiCorp, and IEPA suggested use of the CEC Net System Power calculation. NRDC /TURN/UCS recommended assignment of a coal emissions factor in order to deter LSEs and suppliers from reclassifying coal contracts as unspecified power. DRA also suggested that unspecified power should not be considered as meeting the EPS.

Sempra suggested modifying WREGIS, or some other tracking system, to track emissions from contracts. While this suggestion has significant merit in the longer term, for the purposes of implementing a program by the February 1, 2007 deadline, it is not currently feasible as no tracking system, including WREGIS, is available or being developed that could manage the tracking of emissions from unspecified contracts.

Other parties disagreed with the use of any imputed emissions factor since it is:

1) unlikely unspecified contracts will make up a significant portion of long-term contracts anyway (Constellation), 2) an imputed factor automatically sets up an unproductive binary scheme in which all or none of the resources pass (SCE), or 3) the use of proxies for emissions do not reflect the actual emissions from a resource and therefore all power should be specified (Calpine).

Staff recognizes the imperfect nature of the use of emissions factors. However, for the purposes of implementing an EPS program in the near-term, staff acknowledges the need to determine how unspecified power commitments will be treated. In the near-term, there is no tracking system available to accurately collect emissions information to determine the exact nature of the facilities that lie behind unspecified power deliveries. Staff is not persuaded that unspecified resources should thus be disallowed altogether.

Generally, the Commission is given broad authority to address enforcement and verification of compliance with the program.

Section 8341(b)(3) "The commission shall adopt rules to enforce the requirements of this section, for load-serving entities. The commission shall adopt procedures, for all load-serving entities, to verify the emissions of greenhouse gases from any baseload generation supplied under a contract subject to the green house gases emission performance standard to ensure compliance with the standard."

In looking at alternatives (a)-(d) above, staff characterizes them as following:

a) WECC system average: Incorporates all generation activities throughout the western region.

b) WECC geographic average: Computes an emissions factor for all generation activities in various regions of the WECC system such as the NW, SW, etc.

c) CEC calculated " CA Net System Power Average": This average accounts for and weights by region the differing emissions factors from unclaimed resources generated in CA and imported to CA.

d) Coal emissions factor: would be based upon representative emissions from coal generation.

Based upon review of the data and parties comments, staff finds that the WECC system average is generally not reflective of CA activities or market. Using this average would be somewhat arbitrary as staff does not believe that it is specific enough to load served in CA.

Similarly, the WECC sub-regional geographic averages suffer from the same shortfalls and broad sweeps, and would further penalize and reward LSEs differently based upon the major geographic source of their imported system power, which is largely a function of the location of their service territory within California. While we recognize that a different approach may be necessary for the cap-and-trade program, staff is uncomfortable making a geographic assignment that would set up different regional emissions factors for the purpose of the Phase 1 EPS program.

Regarding the use of coal as a proxy emissions factor, staff does not view this as a reasonable approach. While it is simple to administer, it is not an accurate reflection of the characteristics of all unspecified resources.

Staff acknowledges the concern raised by some parties that LSEs will be inclined to enter into unspecified contracts with high emitting resources in order to circumvent the EPS by having a possible lower emissions rate assigned to that resource. Based upon the comments, especially the assertion that long-term contracts with unspecified resources are a small fraction of the incremental power supply, staff does not anticipate this being a substantial issue. Staff will monitor contracting patterns and behaviors to ensure they do not change for this reason. In addition, staff also has recommended provisions for multiple contracts (see Q7.) to avoid "slicing and dicing" of larger contracts.

The CEC's CA Net System Power Average is currently used by the IOUs for power content labeling purposes. The Average takes into account the geographic origins (in-state and imported) of all of the State's unclaimed power sources, and assigns weights to the relevant emissions factors to create a single factor, that can be applied equally across all CA LSEs. Of the options, this Average and its imputed emission factor is the most representative of CA's unclaimed energy mix. Staff views this to be the superior of the options and recommend its use as it is the most comprehensive and accurate of the options. Staff notes that the CEC is currently refining the methodology for the net system power mix and expects to have an updated version this fall. Staff recognizes that the CEC periodically updates its Net System Power Average and methodology. Therefore, staff recommends that throughout the life of the EPS program, the most recently adopted CEC Net System Power Average be used at the time of evaluation of new or renewed commitments.

Q16. The Staff Revised Proposal does not include offsets or market price safety valves under the interim EPS, but does provide for a case-by-case reliability "safety valve" review by the Commission. Please comment on this aspect of the proposal, and provide your recommendations.

In their responses to this question, parties presented a number of scenarios that might trigger a "safety valve" response or an exemption such as:

_ ability to meet reliability standards established by CAISO, unless they can be met while also meeting the EPS (PG&E, Constellation).

_ any unforeseen circumstances (SDG&E and SoCalGas)

_ investment in advanced coal technologies to support the Western Governor's Conference recommendations (SDG&E and SoCalGas)

_ cost issues that could trigger an "economic safety valve" (SCE)

_ Statutory language allowing the Governor to make modifications to GHG programs in event of extraordinary circumstances, catastrophic events, or threat of significant economic harm- Health and Safety Code Section 38599(a). (Sempra)

_ Jurisdictional issues (PacifiCorp)

In addition, several respondents commented on the use of offsets in the EPS program. LS Power and EPUC/CAC generally support offsets as part of an EPS program. Others recommended coupling offsets with a "safety valve" (Constellation).

Most parties did not support the inclusion of offsets at this time. Calpine viewed them as not fitting with the concept of an EPS program and anticipated unnecessary delays in implementation if offsets were to be included. Constellation and IEPA also did not see this fitting with an interim EPS, and stated that they might be more applicable to a cap program. NRDC/TURN/UCS generally do not support the use of offsets and safety valves with the program.

In the draft proposal, exemptions can be made based upon reliability at the discretion of the Commission. In order to implement an interim program in the near-term, we recommend not including provisions for a safety valve or offsets as part of the initial program as both of these issues would require significant up front analysis and ongoing monitoring. These issues are best addressed as part of Phase 2 of this proceeding focusing on design and implementation of a load based cap.

However, staff recognizes provisions for cost and reliability included in SB 1368 in the following sections:

Section 1(g) "It is vital to ensure all electricity load-serving entities internalize the significant and underrecognized cost of emissions recognized by the PUC with respect to the investor-owned electric utilities, and to reduce California's exposure to costs associated with future federal regulation of these emissions."

Section 8341(d)(6) "In adopting and implementing the greenhouse gases emission performance standard, the commission, in consultation with the Independent System Operator shall consider the effects of the standard on system reliability and overall costs to electricity customers."

Staff modifies its proposal to allow for reliability and cost based exemptions on a case-by-case basis at the discretion of the Commission. Staff recommends no change to the previous proposal regarding offsets or explicit safety valves.

Q17. From a policy perspective, please discuss whether energy service providers, qualifying facilities (QFs) and other jurisdictional load-serving entities (LSEs), including multi-jurisdictional utilities, should be subject to an interim EPS along with PG&E, SCE and SDG&E, should the Commission decide to adopt one. Limit your comments to policy considerations, rather than legal argument.

If you have considered the issue of how the Commission would apply an interim EPS to multi-jurisdictional utilities, please present a protocol for allocating emissions among resources serving multiple states with your post-workshop comments.

Many respondents to the initial proposal, including all three IOUs, GPI, NRDC/TURN/UCS, IEPA, argued that all CPUC jurisdictional LSEs should be included in order to ensure uniformity, consistency and mitigate competitive or cost disadvantage among LSEs. They also identified leakage and shuffling of resources as a potential result of limiting the EPS to IOUs. More broadly, many observed that an EPS program should ideally apply to all LSEs procuring and supplying electricity resources within the State of California. For multi-jurisdictional LSE's, PacifiCorp recommends developing a methodology that takes into account their particular circumstances. Many of the ESPs commenting requested that if required to participate, a process be developed to comport with their existing reporting requirements to the Commission.

EPUC/CAC and Constellation proposed exempting co-generation QF's "so as not to discourage their development." Alternatively, their emissions should only be included to the extent they deliver energy to the LSEs. Calpine suggested that QF's be included, but that the EPS take into account their useful thermal output (converted to an equivalent MWh number) when calculating GHG emissions for purposes of EPS compliance. Such an approach would ensure that the benefits associated with the increased efficiencies of employing cogeneration technology are appropriately recognized.

The issue of cogeneration is addressed in more detail in Q13.

SB 1368 clearly requires the EPS to apply to IOUs, ESPs, CCAs, and Multi-Jurisdictional Utilities (MJUs) alike.

Section 8340(h) states, "Load-serving entity" means every electrical corporation, electric service provider, or community choice aggregator serving end-use customers in the state.

Exceptions to this rule are limited to the following:

Section 8341(d)(9) states, "An electrical corporation that provides electric service to 75,000 or fewer retail end-use customers in California may file with the commission a proposal for alternative compliance with this section, which the commission may accept upon a showing by the electrical corporation of both of the following:

(A) A majority of the electrical corporation's retail end-use customers for electric service are located outside of California.

(B) The emissions of greenhouse gases to generate electricity for the retail end-use customers of the electrical corporation are subject to a review by the utility regulatory commission of at least one other state in which the electrical corporation provides regulated retail electric service."

Staff recommends that the EPS be applicable to all of the CPUC jurisdictional LSEs in compliance with Sections 8340(h) and 8341(d)(9).

The Commission's jurisdiction regarding the administration and enforcement of the EPS program is as follows:

For IOUs- Section 8341(b)(1): "The commission shall not approve a long-term financial commitment by an electrical corporation unless any baseload generation supplied under the long-term financial commitment complies with the greenhouse gases emission performance standard established by the commission pursuant to subdivision (d)."

For ESPs and CCAs- Section 8341(b)(2), "The commission may, in order to enforce the requirements of this section, review any long-term commi