Findings of Fact
1. Energy efficiency is the cheapest and most effective resource for reducing GHG emissions in the electricity and natural gas sectors.
2. Many non-price market barriers to energy efficiency investment exist and will continue to exist even if a GHG emissions allowance cap-and-trade program is implemented.
3. As the cost of GHG mitigation becomes reflected in the cost of energy, more energy efficiency opportunities should become cost-effective. However, as more "low-hanging fruit" energy efficiency is achieved, incremental energy efficiency options may become more expensive.
4. It is reasonable for the State of California to require comparable investment in energy efficiency by all retail providers in California, including both investor-owned and publicly-owned utilities.
5. Achieving the goal of all cost-effective energy efficiency will require a continuation of existing direct regulatory/mandatory requirements, expansions of existing requirements and development of new ones where appropriate, and implementation of other innovative approaches such as market-based strategies.
6. It is reasonable for the State of California to set a goal of attainment of all cost-effective energy efficiency investment.
7. Renewable mandates play an important role in achieving aggressive renewable energy penetration, since they provide a long-term signal that can lead to market transformation of new renewable technologies and potential cost reductions.
8. E3 estimates that GHG emissions reductions obtained through achievement of 33% electricity from renewables may have an average incremental cost of $133 per ton, compared to the current 20% RPS mandate.
9. Renewable energy provides environmental co-benefits, including reducing other non-GHG pollutants, when sited in California.
10. Significant implementation barriers exist to the continued deployment of renewable energy in California.
11. Increased renewable energy penetration would increase fuel diversity.
12. California's longer term 2050 GHG reduction goals will require significantly reducing the GHG footprint of the electricity sector.
13. Obtaining 33% of the electricity delivered to customers from renewable resources by 2020 would be an important step in achieving this transformation.
14. It is reasonable for the State of California to set as requirements that by 2020 at least 33% of California's electricity needs be met by renewable resources, and that by 2020 each retail provider obtain at least 33% of the electricity delivered to its customers from renewable resources.
15. E3's approach and analysis to estimating costs from reducing GHG emissions are reasonable for the purpose of informing our recommendations to ARB.
16. E3 estimates that the Accelerated Policy Case would result in GHG emissions totaling 79 MMT CO2e for the electricity sector in 2020.
17. We did not study the cost and rate impacts on consumers of increasing energy efficiency goals, renewable energy mandates, or levels of CHP beyond those in E3's Accelerated Policy Case. Prior to increasing these policies/mandates, the costs of additional reductions should be compared against the costs of mitigating GHG emissions across the California economy.
18. Linkage with a regional emissions trading system that includes all jurisdictions in the Western electricity grid would likely result in coal-fired generators operating less, would significantly mitigate opportunities for deliverers to mask the carbon intensity of electricity through "contract shuffling," and may result in low-carbon generation displacing either coal or natural gas-fired generation depending on time and location.
19. The Western Climate Initiative has issued draft design principles that target an opening date of January 1, 2012 for a linked regional cap-and-trade program.
20. Linking with other state cap-and-trade programs through the Western Climate Initiative would remove or mitigate some of the challenges of a California-only approach.
21. The modeling effort in this proceeding did not include effects of Western Climate Initiative or national approaches to controlling GHG emissions.
22. The level of responsibility or "burden" under AB 32 should be proportional and fair to consumers in all sectors of the economy.
23. ARB's Draft Scoping Plan would assign approximately 40% of the economy-wide responsibility for mandatory emissions to the electricity sector, even though electricity represents only 25% of the statewide emissions. This requirement would result in electricity sector emissions in 2020 roughly equal to the level that E3 estimates under the Accelerated Policy Case.
24. Under a cap-and-trade program, the responsibility for reducing emissions can be separated from the recovery of the cost of the emission reductions.
25. If ARB implements a multi-sector cap-and-trade program in California, it is reasonable to allocate allowances proportionally among the sectors in the cap-and-trade program, based on relative emissions during an historical baseline period.
26. It is reasonable that the trajectory of a multi-sector cap and the required annual reductions generally be a straight-line reduction between 2012 and 2020 for all sectors in the California cap-and-trade program, to ensure steady progress toward the 2020 goals. However, development through the Western Climate Initiative of regional emission reduction programs, which may include transportation and other sectors, may affect the schedule for implementing emission reductions.
27. A centralized auction of allowances undertaken by ARB or its agent would provide market liquidity, ensure that all deliverers have equal access to allowances, and reduce or avoid the need for a set-aside or other administrative accommodation for new entrants.
28. There is an expectation that if allowances are auctioned GHG compliance costs would be internalized in wholesale electricity prices, sending more accurate price signals that would encourage participants in the electricity sector to reduce emissions.
29. Auctioning allowances would result in entities with compliance obligations bearing the full financial responsibility for emissions associated with electricity that they deliver to the California grid.
30. Auctioning would preclude windfall profits from allowance rents to independent deliverers.
31. Distributing some free allowances to deliverers would reduce short-term impacts on generating resources, and would help generators adapt to the new regulatory environment.
32. A transition to auctioning would help protect ratepayers if problems arise as ARB implements AB 32 and experience is gained with the auctioning process.
33. A transition to 100% auctioning by 2016 would ensure that any allowance rents would be short-term and would give existing high-emitting resources time to adjust their generation investments.
34. It is reasonable to introduce auctioning in a phased approach, with 100% auctioning by 2016, so that California can reap initial benefits from auctioning and, at the same time, provide some protection and stability while the cap-and-trade market develops and matures.
35. A primary consideration in the early years of a cap-and-trade program should be to ensure that economic harm is mitigated to the range of market participants in the electricity sector, including customers, retail providers, and deliverers.
36. A fuel-differentiated output-based allocation approach with distributions limited to deliverers of electricity from emitting generation resources (including unspecified sources) would provide all deliverers with allowances roughly in proportion to the amount they need and would reduce the potential for allowance rents.
37. A fuel-differentiated output-based allocation approach with distributions limited to deliverers of electricity from emitting generation resources would avoid undue economic harm to California electricity consumers who are currently locked into a certain degree of dependence on coal.
38. In a fuel-differentiated output-based allocation approach, it is reasonable that a higher weighting factor be applied for all coal generation delivered to the California grid.
39. If 100% auctioning is not implemented by 2016, an important longer-term goal of deliverer distributions should be to provide strong incentives for GHG reductions.
40. It is reasonable, if 100% auctioning is not implemented for the electricity sector by 2016, that allowance distributions to deliverers transition toward an output-based approach that weights all types of generation equally, to be reached by 2020 if 100% auctioning is not achieved by that time.
41. A centralized auction undertaken by ARB or its agent, in which retail providers rather than the State own most or all of the electricity sector allowances at the time they are auctioned would simplify the auctioning and revenue distribution process, in that auction revenues would pass directly to the retail providers.
42. A centralized auction undertaken by ARB or its agent in which retail providers are required to sell any allowances they receive would remove anti-competitive concerns regarding the distribution of allowances to retail providers.
43. It is reasonable to require that retail providers sell any allowances they receive in a centralized auction undertaken by ARB or its agent. This finding does not apply to allowances that a vertically-integrated entity that is both a retail provider and a deliverer may receive based on its deliveries to the grid.
44. It is reasonable to require that each retail provider receive all auction revenues from the sale of its allowances through the centralized auction.
45. Allocating allowances to retail providers based on historical emissions in their electricity portfolios would accommodate carbon-intensive retail providers that may face relatively high rate impacts due to compliance costs.
46. A long-term priority for allocating allowances is to provide strong incentives for increased reliance on low- and non-emitting resources and to provide consistent signals to all retail providers regarding the value of low-emitting portfolios.
47. It is reasonable to transition allocation of allowances to retail providers from an historical emissions basis to a sales basis by 2020 because a sales-based allocation would provide a long-term incentive to reduce reliance on high-emitting resources.
48. To meet the goals of AB 32, California is preparing to implement ambitious energy efficiency and renewable energy mandates.
49. Meeting the targets for the electricity sector outlined in ARB's Draft Scoping Plan will require significant additional expenditures on energy efficiency measures and the development of new renewable resources.
50. It is reasonable to require that all auction revenues be used for purposes related to AB 32 and that all auction revenues from allowances allocated to the electricity sector be used to finance investments in energy efficiency and renewable energy or for bill relief, especially for low income customers.
51. Electricity delivered to the California grid by CHP facilities is indistinguishable from electricity delivered from non-CHP sources.
52. With respect to GHG emissions, all electricity generated by a CHP facility is identical whether the electricity is delivered to the grid or consumed on-site.
53. It is reasonable to include the emissions associated with all electricity consumed in California and generated by CHP facilities in excess of a minimum size threshold, whether the electricity is used on-site or delivered to the grid, in a multi-sector cap-and-trade system.
54. It is reasonable to provide comparable GHG regulatory treatment for all CHP facilities that exceed the minimum size threshold, regardless of whether they deliver electricity to the grid or solely serve on-site load, and regardless of the metering configuration used.
55. It is reasonable to use the same minimum size threshold used for other deliverers to determine which CHP facilities should be included in a multi-sector cap-and-trade program.
56. It is not necessary to attribute GHG emissions from CHP facilities to a unique CHP sector if the GHG emissions are included in a multi-sector cap-and-trade program.
57. It is reasonable to treat entities that deliver CHP-generated electricity to the grid like other deliverers for GHG regulatory purposes, and to treat CHP operators comparable to deliverers for the portion of CHP-generated electricity that is consumed on-site.
58. It is reasonable to allocate allowances to entities that deliver CHP-generated electricity to the grid, and to CHP operators for CHP-generated electricity that is consumed on-site using the fuel-differentiated output basis, as described in this decision.
59. To the extent that CHP facilities provide electricity that is consumed on-site, distributing allowances to CHP facility operators on the same basis as retail providers would provide equitable treatment for CHP facilities.
60. Linking California's cap-and-trade program with other trading systems would add liquidity and efficiency to California's trading market.
61. Bilateral linkage would allow California to ensure that any allowances accepted by California entities from other systems are of comparable quality to California allowances.
62. It is reasonable for California to pursue bilateral linkage with other local, regional, national, and international GHG cap-and-trade systems that have comparable stringency, monitoring, compliance, and enforcement provisions.
63. Unique characteristics of the electricity sector necessitate that the cap-and-trade market include a reasonable range of flexible compliance options in order to provide needed flexibility to the sector while maintaining the environmental integrity of the emissions cap.
64. Price triggers and safety valves could very likely distort or defeat the cap-and-trade market by creating uncertainty that investments in emissions reduction technologies will achieve returns commensurate with the level of reductions needed to meet the State's emissions reduction goals.
65. Declining allowance prices over time are likely to indicate that the market is working to drive sufficient investment toward the required emissions reductions.
