8. Assignment of Proceeding
Michael R. Peevey is the Assigned Commissioner. Meg Gottstein is the assigned ALJ for the procurement incentives portion of this proceeding.
1. The electric power sector is the second-largest source of GHG emissions in California, after automobiles.
2. Establishing a GHG emissions cap for LSEs is consistent with, and follows the lead of Governor Schwarzenegger's Executive Order S-3-05. It is also consistent with the goals of the EAP and this Commission's October 6, 2005 Policy Statement on Greenhouse Gas Performance Standards.
3. California relies on significant sources of generation imported into California from other states. A load-based cap on GHG emissions can minimize leakage across California borders.
4. Establishing allowances under the load-based cap based on "tons of carbon-dioxide equivalent" will create allowances that are fungible and compatible with any other GHG cap-and-trade regime that may be developed in the future.
5. As discussed during workshops, there are approaches that can be taken during implementation of a load-based cap to track and quantify potential contract shuffling. As other states follow California's lead on limiting GHG emissions, contract shuffling will become moot.
6. Regulating the GHG emissions of California IOUs falls squarely within the Commission's authority over their procurement activities.
7. Pub. Util. Code § 380(e) gives this Commission the authority to establish resource adequacy requirements on all IOUs, CCAs, and ESPs in California in a "non-discriminatory" manner, and makes these LSEs subject to the same requirements for resource adequacy and the RPS program. Section 380(e) along with other statutory provisions reinforce the Commission's authority over CCAs and ESPs for procurement related activities, in particular, the RPS program.
8. Shareholder financial incentives can help align ratepayer and shareholder interests.
9. Given the multi-attribute nature of the various resources in the portfolio, it is doubtful that a single cost-optimization metric applied to the entire procurement portfolio would yield results consistent with EAP loading order of preferred resources and other Commission procurement policies. Even if such an approach existed in theory, it appears highly uncertain that a portfolio-wide approach to financial incentives could be put into practice in a reasonable timeframe.
10. Moving forward with category-specific financial incentives is not contingent upon putting a GHG emissions cap in place.
11. Moving forward with the development of financial incentives for preferred resources is worthwhile and consistent with the policies articulated in prior Commission decisions, as well as with the action items outlined in the EAP. In particular, developing financial incentives for energy efficiency investments addresses the need to bring those investments in line with traditional supply-side resources when it comes to opportunities to earn returns on those investments.
12. TURN's categorical rejection of financial incentives for energy efficiency and other EAP preferred resources ignores the policies articulated by the CPUC in prior decisions and the action items contained in the EAP.
13. Financial incentive mechanisms should provide an opportunity to earn financial rewards balanced by the risk of financial penalties for poor performance. Financial rewards should be granted for performance that exceeds performance thresholds that are tied to Commission savings goals or, in the case of RPS resources, to Legislative mandates.
14. It would be premature to commit today to a timeframe for considering financial incentives for renewable resource procurement, given the plethora of issues under consideration related to RPS implementation in R.04-04-026.
15. It would be premature to explore financial incentives for demand response programs until the Commission undertakes the additional activities identified in D.05-11-009 that will ensure that these programs provide full value to California. These include the development of a cost-effectiveness methodology and measurement and verification protocols.
16. The concept of allowance sale incentives in conjunction with a GHG emissions cap has appeal, and should be further explored in the implementation phase of this proceeding. If such an incentive mechanism is established, the resource-specific incentives should be designed work in tandem with this concept, in order to eliminate any double-counting of financial rewards or penalties.
17. The use of a prospective year as the baseline for a GHG emissions cap has the potential for creating a perverse incentive for LSEs to (1) not take immediate measures to start reducing GHG emissions, and/or (2) take measures that would actually increase their GHG emissions. The use of a historical baseline avoids this perverse incentive.
18. An approach that would calculate a baseline and associated emissions cap from the emissions profile of an adopted procurement plan would not truly be a baseline because it would be calculated using various assumptions and emissions factors. Therefore, it could not be relied upon to gauge true changes from year to year by comparing certified emissions.
19. Using a historical baseline is consistent and compatible with efforts underway on the state and international level to address climate change.
20. A historical reference point, rather than a prospective one based on procurement plans, should be used to establish the GHG emissions cap adopted in this decision.
21. As discussed in this decision, the selection of 1990 as the baseline for a load-based GHG emissions cap allows the greatest harmonization with the Governor's Executive Order and with international efforts to address climate change.
22. The record needs to be further developed with respect to the implementation issues associated with using 1990 as the reference year, including the availability of adequate historical emissions data for the IOUs and other LSEs.
23. The record needs to be further developed with respect to the appropriate level of emissions reductions (and associated caps) over time, relative to the baseline. An assessment of achievable potential in GHG reductions using "supply curves" of GHG reduction measures may help inform this process, and should be explored further during the implementation phase.
24. The variability of hydroelectric conditions has an impact on the GHG emissions profile of LSEs in any given year. How best to account for this hydro variability should be explored during the implementation phase.
25. As discussed in this decision, the CCAR is an essential component to the implementation of today's adopted policies.
26. Requiring LSEs to file information about existing GHG emissions and the GHG emissions impacts of their planned procurement activities will enable the CPUC to establish GHG reduction requirements (and associated caps) that most effectively reduce the absolute level of GHG emissions over time.
27. An auction of allowances with few buyers, which is the case here, would be economically inefficient and prone to market power abuses.
28. Administrative allocation of allowances, rather than auction, avoids the need for the CPUC to undertake the complex set-up of an auction structure and rules.
29. Administrative allocation of GHG emissions allowances is more conducive to the CPUC's regulatory process for addressing procurement related issues.
30. The manner in which the CPUC will allocate GHG emission allowances needs to be explored in detail during the implementation phase.
31. Limiting the use of emissions offsets to actions directly related to utility activities (e.g., diesel pump electrification) will encourage technological growth in areas that reduce the GHG emissions footprint of energy use within the utility service territory.
32. Emissions offsets for activities within California will be easier to track and verify than out-of-state offsets, at least at this time.
33. Allowing trading of emissions offsets is administratively complex, and not the best place to focus initial implementation efforts.
34. Over the longer term, trading of emissions allowances may enable lower-cost reductions of GHG emissions.
35. Borrowing of emissions allowances from future years will discourage early action to reduce GHG emissions.
36. Limited banking of emissions allowances can help LSEs comply with GHG emissions caps. Allowing three years of banking is consistent with Commission rules under RPS flexible compliance.
37. Without some form of penalty structure, compliance with the GHG emissions cap will only be voluntary.
38. The CPUC does not have enough information about appropriate penalty levels or mechanisms at this time. However, the concept of structuring penalties in the form of alternate compliance payments has considerable appeal, based on the record in this phase of the proceeding, and should be further explored during the implementation phase.
39. The registration of LSEs and resource suppliers to LSEs with CCAR is an important step in quantifying existing and future emissions.
40. The IOU respondents in this proceeding (PG&E, SCE, and SDG&E) are registered with CCAR and report their emissions using CCAR's reporting protocols.
41. Requiring that all power purchase agreements signed by PG&E, SDG&E, and SCE include a provision that the generation supplier register with CCAR will help facilitate emissions reporting and tracking in California. This requirement still leaves a significant portion of the existing supply market, as well as the ESP suppliers, left to voluntary registration with the CCAR.
42. SDG&E's suggestion in this proceeding, namely to assign the emissions value of coal to any non-renewable supplies of electricity with fossil fuel emissions that are unregistered with the CCAR, addresses this larger portion of the market. It does so by encouraging the LSEs purchasing those supplies to negotiate with suppliers for CCAR registration.
43. As discussed in this decision, it may be appropriate to discontinue the use of a GHG or carbon adder once a working GHG emissions cap is in place.
44. Any long-term effort to limit carbon emissions should address natural gas use both for electricity production and directly by customers. However, until the requisite emission reporting and certification protocols become available, it is premature to establish GHG emissions reductions (or associated caps) for non-electric generation usages of natural gas. The implementation phase should further define the steps the CPUC should take to ensure that GHG emissions associated with customer use of natural gas are incorporated into a procurement incentive framework in the future.
45. As discussed in this decision, SDG&E has submitted a proposal for shareholder incentives that does not fit within the scope or goals of our inquiry in this proceeding.
1. The CPUC should continue to coordinate with Governor Schwarzenegger's Climate Action Team, as well as other regional, national, and international efforts to reduce GHG emissions.
2. As described in this decision, the CPUC should establish a load-based cap on GHG emissions for PG&E, SDG&E, SCE, and non-utility LSEs that provide electric power to customers within respondents' service territories.
3. The setting of a load-based GHG emissions cap by the CPUC is not prohibited by or inconsistent with the Interstate Commerce Clause of the U.S. Constitution.
4. The CPUC has authority to regulate GHG emissions within its overall authority over the procurement activities of California IOUs. As discussed in this decision, this authority logically extends to the GHG emissions of CCAs and ESPs under the legal authority granted by Pub. Util. Code § 380(e) and other statutory provisions.
5. In a separate phase of this proceeding, its successor proceeding, or a new rulemaking, the CPUC should address the implementation of today's decision.
6. In addition to establishing a load-based GHG emissions cap, the CPUC should evaluate proposals for shareholder financial incentives in resource-specific proceedings, beginning with energy efficiency and including renewable energy in the future. As discussed in this decision, the CPUC may consider the issue of shareholder incentives for demand response programs at a later date.
7. The CPUC should require LSEs to file information about their GHG emissions baselines and the GHG emissions impacts of their planned procurement activities in their 2006 long-term procurement plans.
8. The CPUC should require that all future power purchase agreements signed by PG&E, SDG&E, and SCE contain a requirement that the generation supplier register with the CCAR. The CPUC should consider extending this requirement to the smaller electric IOUs under its jurisdiction after further consideration of this issue in a proceeding to which these companies are also respondents.
9. For purposes of determining emissions baselines and caps, any non-renewable generation that is supplied to an LSE by a supplier than is not registered with the CCAR, should be automatically assigned the emissions value of coal generation.
10. The CPUC should continue the use of the carbon adder ordered in D.04-12-048 until after the CPUC has considered the value of continuing with a carbon adder in the context of a fully implemented GHG emissions cap.
11. The CPUC should delegate to the Assigned Commissioner and assigned ALJ the management of the implementation steps associated with today's decision.
12. The CPUC should deny SDG&E's request for approval of its incentive proposal at this time.
13. In order to proceed as expeditiously as possible to implement today's adopted policies, this order should be effective immediately.
IT IS ORDERED that:
1. The California Public Utilities Commission (CPUC or Commission) shall proceed to establish a load-based cap on greenhouse gas (GHG) emissions for Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E), Southern California Edison Company (SCE) ("the utilities") and non-utility load serving entities (LSEs) that provide electric power to customers within the utilities' service territories.
2. Implementation of a load-based cap shall be guided by the following:
a. The load-based cap should include emissions allowances for "tons of carbon dioxide equivalent."
b. The load-based cap should include provisions for lowering the GHG reduction requirements (and associated cap) over time, relative to a baseline level of GHG emissions.
c. The baseline should be established on a historical year basis, with 1990 as the preferred reference year. A final determination on this matter should await further consideration of implementation issues associated with using this particular year as the reference, including the availability of adequate historical emissions data for the investor-owned utilities and other LSEs.
d. GHG emissions allowances under the load-based cap should be allocated administratively by the CPUC.
e. The use of emissions offsets should be initially limited to actions directly related to utility activities (e.g., diesel pump electrification) and to activities occurring within California.
f. Trading or borrowing from future years' allowances should not initially be allowed.
g. Limited banking of emissions credits for up to three years should be allowed.
h. A penalty mechanism should be developed, with preference towards structuring penalties as alternative compliance payments.
3. Allowance sale incentives, whereby the CPUC would certify GHG emissions allowances for sale by the utilities outside of California to the benefit of their shareholders, shall be further considered and developed during the implementation of today's decision.
4. During implementation, the CPUC shall identify the issues for which energy service providers, community choice aggregators and the utilities should be subject to the same terms and conditions of GHG reduction requirements and associated caps, and those where differences may be appropriate.
5. During implementation, the CPUC shall further define the steps it will take to ensure that GHG emissions associated with customer use of natural gas are incorporated into a procurement incentive framework in the future.
6. Implementation of today's decision shall be addressed in a subsequent phase of this rulemaking, or its successor proceeding, or in a new rulemaking opened by the Commission specifically for this purpose.
7. As discussed in this decision and Decision (D.) 05-09-043, the CPUC shall proceed to develop a risk/reward incentive mechanism for energy efficiency in Rulemaking (R.) 01-08-028, or its successor proceeding.
8. All LSEs that are required to file a 2006 long-term procurement plan shall include the following information in their plans:
a. GHG emissions baseline information about the LSE's existing resource portfolio, and
b. The emissions characteristics associated with its preferred resource plan and any alternative scenarios presented or proposed.
9. As of the effective date of this decision, all power purchase agreements that PG&E, SDG&E, and SCE sign shall include a provision requiring supplier registration with the California Climate Action Registry. The CPUC may extend this requirement to the smaller utilities under its jurisdiction after further consideration of this issue in a proceeding to which these companies are also respondents. Any non-renewable supplies of electricity with fossil fuel emissions that are unregistered with the California Climate Action Registry shall automatically be assigned the emissions value of coal.
10. The use of the carbon adder adopted in D.04-12-048 shall remain in effect for procurement activities until further notice.
11. SDG&E's request for approval of its incentive proposal in this proceeding is denied.
12. The Assigned Commissioner and assigned Administrative Law Judge may make rulings, hold prehearing conferences, and conduct other activities as necessary to manage the implementation of today's decision.
13. This decision shall be served on the service list in this procurement proceeding (R.04-04-003), the energy efficiency rulemaking (R.01-08-028), the avoided cost rulemaking (R.04-04-025), the community choice aggregator rulemaking (R.03-10-003), ongoing transmission proceedings (R.04-01-026 and I.00-11-001), renewables portfolio standard rulemaking (R.04-04-026), and the distributed generation rulemaking (R.04-03-017).
14. This proceeding shall remain open to address other procurement-related issues, as appropriate.
This order is effective today.
Dated , at San Francisco, California.
ATTACHMENT 1: ABBREVIATIONS AND ACRONYMS
Abbreviation or Acronym |
Name |
ACPs |
alternative compliance payments |
ALJ |
Administrative Law Judge |
CAC |
Cogeneration Association of California |
CalEPA |
the California Environmental Protection Agency |
CCAR |
California Climate Action Registry |
CCAs |
community choice aggregators |
CEC |
the California Energy Commission |
CPUC or Commission |
the California Public Utilities Commission |
D. |
Decision |
Duke |
Duke Energy North America |
EAP |
Energy Action Plan |
EPUC |
Energy Producers and Users Coalition |
ESPs |
electric service providers |
GHG |
greenhouse gas |
GPI |
Green Power Institute |
IOUs |
investor-owned utilities |
LSEs |
load serving entities |
NRDC |
Natural Resources Defense Council |
ORA |
the Office of Ratepayer Advocates |
PG&E |
Pacific Gas and Electric Company |
R. |
Rulemaking |
RPS |
renewables portfolio standard |
SCE |
Southern California Edison Company |
Sempra |
Sempra Global |
TURN |
The Utility Reform Network |
UCS |
the Union of Concerned Scientists |
(END OF ATTACHMENT 1)
