4. Emission Reduction Measures and Overall Contributions of Electricity and Natural Gas Sectors to AB 32 Goal
ARB's Draft Scoping Plan calls for an "ambitious but achievable" reduction in California's carbon footprint. In order to achieve the statutory goal of returning statewide emissions to 1990 levels, the Draft Scoping Plan estimates necessary reductions of 169 MMT of CO2e. Both the electricity and natural gas sectors are expected to be key contributors in achieving that goal.
This section addresses the level of emission reductions that can be achieved by the electricity and natural gas sectors by 2020.26 In addition, we indicate best estimates of the cost at which varying levels of sector-wide emissions reduction may be achieved, informing recommendations regarding appropriate distribution of emissions reduction responsibility across sectors of California's economy. Information presented in this section should also inform overall emissions cap levels (i.e., the total number of allowances allocated) for a cap-and-trade program inclusive of the electricity sector, if one is implemented.
4.1. Emission Reduction Measures
In this decision, an "emission reduction measure" describes a means by which the sector as a whole can achieve GHG emissions reductions. Our goal is to estimate, using best-available information, the overall level of reductions that may be expected from the electricity and natural gas sectors within AB 32's 2020 timeframe; which resource areas, generally, those reductions will derive from; and the associated costs. While the realization of certain reductions estimated herein may require support through the establishment of new or accelerated policies, it is not our intent to do so by way of this decision.
In basic terms, electricity sector emission reductions derive from the displacement of GHG-emitting generation. Such displacement can be achieved either through measures that work on the supply side to reduce the carbon intensity of electricity deliveries to consumers, or through demand-side measures that either reduce the overall demand for electricity from the transmission and distribution grid or generate electricity on the customer side of the meter. For the natural gas sector, emission reduction opportunities are largely limited to demand reductions and solar hot water heating,27 as natural gas demand is served by a uniform fuel source with fixed carbon content. However, some parties have suggested opportunities by which fossil natural gas supplies can be replaced by biogenic sources (biomethane), effectively reducing the net carbon intensity of servicing natural gas demand for certain end uses.
Considering GHG reduction measures within the electricity and natural gas sectors necessarily entails bringing together a host of efforts that have been underway in California for many years. Although not all of such measures have been motivated directly by climate concerns, they nonetheless contribute to achieving targeted GHG reductions.
The emission reduction measures examined in this proceeding include increased penetrations of the following:
· energy efficiency through codes and standards and a host of programs provided by utilities or other providers,
· utility-scale renewable generation by way of the State's RPS mandate and other potential options to ensure increased renewable investment,
· distributed photovoltaics through the Million Solar Roofs Initiative,28 and
· CHP facilities.
Other measures suggested by parties, though not analyzed in depth in this proceeding, include solar hot water heating, biomethane, Smart Grid technologies, and carbon capture and storage.
Currently, the best available information regarding the quantified emission reductions stemming from the various measures examined in this proceeding comes from the work undertaken by E3 described in more detail in Section 3 above. In the scope of this work, E3 gathered detailed information regarding the market potential in each of the above-bulleted areas.
In D.08-03-018, we recommended that ARB incorporate into its Scoping Plan a goal of achieving all cost-effective energy efficiency in the State, through a combination of utility programs and non-utility actions and initiatives, including mandatory standards. ARB's Draft Scoping Plan picks up on the D.08-03-018 recommendation and proposes an aggressive pursuit of energy efficiency opportunities to assist in meeting AB 32's emission reduction goals.
In particular, the Draft Scoping Plan would set new targets for statewide energy demand reductions of 32,000 GWh and 800 million therms from business-as-usual projections for 2020. These targets apply to both investor-owned and publicly-owned utilities, and are expected to be achieved through a combination of means, including enhancements to existing utility programs such as increased incentives, more stringent building codes and appliance efficiency standards, and a concerted effort to transform consumers' use of energy products.
In D.08-07-047, adopted on July 31, 2008 in R.06-04-010, the Public Utilities Commission adopted new energy efficiency goals for the years 2012-2020 for investor-owned utility service territories. The purpose of goal-setting on this time frame was in large part to assist in informing ARB in the development of its Scoping Plan. The adopted goals, which were informed by Itron's most up-to-date assessment of energy efficiency potential within investor-owned utility service territories, take into account savings from the entire breadth of energy efficiency opportunities. In addition to direct savings from the investor-owned utilities' programs, they include recognition of State building and appliance standards and expected federal appliance standards, the Public Utilities Commission's Big Bold energy efficiency strategies, and AB 1109 (requiring improvement in general service lighting). The goals include total energy savings from new investor-owned utility programs of over 16,000 GWh and 620 million therms between 2012 and 2020. Including expected savings from current programs between 2008 and 2012, total electricity savings would exceed 26,000 GWh.
As mentioned above, we support a goal of achieving all cost-effective energy efficiency, through a combination of means. We recommend that ARB set electricity and natural gas energy efficiency requirements in its Scoping Plan at the level of all cost-effective energy efficiency, with energy efficiency goals for investor-owned utilities set based on those adopted in D.08-07-047, as may be revised and updated by the Public Utilities Commission from time to time. We recommend further that ARB consider leveraging the substantial analytic work and stakeholder input embodied within the recently adopted California Long-Term Energy Efficiency Strategic Plan as a roadmap to achieving these ambitious and unprecedented levels of energy savings across the State.
As part of its modeling, E3 has incorporated into its GHG Calculator scenarios the same underlying energy efficiency potential data that has informed the Public Utilities Commission's energy efficiency 2020 goal setting. While E3's Reference Case reflects business-as-usual with respect to energy efficiency savings, the Accelerated Policy Case reflects the achievement of Itron's "high goals" scenario. The E3 modeling results indicate that achieving Itron's "high goals" for energy efficiency would reduce GHG emissions in 2020 by an additional 10.2 MMT compared to business as usual and that these reductions would come at an incremental cost of $63 per ton.
Several parties comment on the energy efficiency assumptions underlying E3's model. PG&E argues that, even after improvements between Stage 1 and Stage 2 to the model's representation of energy efficiency, energy efficiency costs assumed in the modeling are still "orders of magnitude" too low. As a result, PG&E suggests that E3 change the Accelerated Policy Case energy efficiency assumption to reflect Itron's "low" goals.
SCE is of the view that the Stage 2 energy efficiency scenarios are much better than the Stage 1 assumptions, but remains skeptical that Itron's "high" and "mid" goals are achievable. Due to uncertainty surrounding the unprecedented levels of energy efficiency program achievement in the Itron scenarios, PG&E argues that ARB should not assume in its Scoping Plan that either the "high" or the "mid" goals case will be achieved. PG&E suggests that, at the very least, the Commissions should conduct sensitivity analyses on energy efficiency costs and/or communicate model results to ARB with an acknowledgement of the uncertainty associated with different outcomes.
In this decision, we reaffirm our commitment to achieving all cost-effective energy efficiency in California. Energy efficiency is, as always, the cheapest and most effective energy resource, and is now our best means to reduce GHG emissions in the electricity and natural gas sectors. Making this happen will require a focused effort and new, aggressive approaches to delivering efficiency options to consumers.
Given that current levels of investment in energy efficiency do not capture the entirety of what is cost-effective, we do not agree with those parties who argue that instituting a cap-and-trade program will make energy efficiency mandates unnecessary. Indeed, many non-price market barriers to energy efficiency investment exist today and will continue to exist even if a GHG emissions allowance cap-and-trade program is implemented.
In addition, as the cost of GHG mitigation is increasingly reflected in the cost of energy, more and more energy efficiency opportunities should become cost-effective over time. However, as more "low-hanging fruit" energy efficiency is achieved, incremental energy efficiency options may become more expensive. One of the biggest uncertainties associated with E3's modeling work and our overall analysis is the anticipated cost of achieving extremely high levels of energy efficiency. Such scenarios will require activities and technologies that have not been accomplished with existing approaches; therefore, there is little empirical evidence to verify cost assumptions or verify successful delivery mechanisms.
In order to meet our aggressive goals, we will need to engage in new and innovative approaches to delivering energy efficiency. Although utility programs and building codes and appliance standards have been successful, we cannot expect that the existing mechanisms alone will deliver all cost-effective energy efficiency. The Public Utilities Commission engaged a wide array of stakeholders including builders, developers, local government, and other State agencies to develop the California Long-Term Energy Efficiency Strategic Plan as a means of identifying further mechanisms and approaches.
At a minimum, we expect to develop much higher requirements for building codes and appliance standards in California through the Energy Commission's ongoing processes. We also expect higher energy efficiency requirements for both investor-owned utilities and publicly-owned utilities. As explained in D.08-03-018, we recommend that the State require comparable investment in energy efficiency from both investor-owned and publicly-owned utilities. ARB may be able to require energy efficiency investments by publicly-owned utilities or it may seek additional Legislative authority to accomplish this objective. In either case, we do not mean to suggest that the investor-owned and publicly-owned utilities must choose the same programs or approaches to energy efficiency investment; we simply encourage similarly aggressive levels of investment and delivered savings expectations from all retail providers.
In addition, through the Energy Commission's Integrated Energy Policy Report process and implementation of the California Long-Term Energy Efficiency Strategic Plan, we expect to engage a number of additional approaches including, but not limited to, energy use benchmarking and disclosure requirements, building and industrial certification and labeling programs, time-of-sale upgrade requirements, comprehensive whole-house retrofit programs, new financing instruments, integrated marketing and awareness campaigns, Smart Grid innovations, quality installation, maintenance and branding programs for air cooling technologies, more comprehensive technical and regulatory assistance programs, expanded training programs, and federal and State tax incentives. These initiatives are expected to be carried out by a wide range of actors. They will accelerate achievement of long-term energy efficiency savings needed to reach energy efficiency goals for 2020, and will advance market transformation policies toward the "Big Bold" programmatic initiatives adopted by the Public Utilities Commission in D.07-10-032: that, "[a]ll new residential construction in California will be zero net energy by 2020; [a]ll new commercial construction in California will be zero net energy by 2030; and [t]he HVAC industry will be reshaped to assure optimal performance of HVAC equipment." (D.07-10-032, p. 38.)
We are aware that some sectors, including the industrial sector, may have AB 32 compliance obligations themselves as part of a cap-and-trade program or other AB 32 regulations. Therefore, monitoring of energy efficiency achievements in those sectors may require addressing complex issues including the tracking of cost contributions, e.g., whether ratepayer or private funds were used, and the attribution of energy savings and GHG reductions achieved, e.g., to the industrial entity, the utility, or the cap-and-trade market.
Over the next year, the Energy Commission will begin development of the next update to the mandatory Building Energy Efficiency Standards and development of advanced or "reach" standards for higher voluntary levels of energy efficiency, and will develop recommendations for the integration of renewable energy system requirements into future Building Energy Efficiency Standards. These efforts will assist with meeting AB 32 GHG emission reduction goals. The Energy Commission is also working closely with ARB on development of a GHG Performance Standard for supermarkets and other buildings with large refrigeration systems which will likely become part of the proposed 2011 Title 24 Building Energy Efficiency Standards.
In addition, we are interested in investigating the use of market-based approaches to achieve additional energy efficiency. Approaches utilizing "white certificates" or "white tags" have been employed in certain states and countries, and operate similar to RECs in areas with renewables obligations that can be met with tradable certificates. Such approaches may represent a supplemental, market-based mechanism for capturing emission reductions and encouraging additional energy efficiency investment in addition to that occurring through mandatory codes and standards, utility programs, industrial sector caps, and voluntary actions as energy efficiency becomes "business as usual."
Therefore, we reiterate our support of attainment of the goal of all cost-effective energy efficiency investment. We note that achieving that goal 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 the market-based strategies described above. We reaffirm our commitment to working with ARB on determining ways to deliver the most energy efficiency savings possible.
We expect that the level of savings to be achieved through augmented codes and standards will continue to be developed through Energy Commission efforts, while the mandatory minimum levels of energy efficiency achievement for investor-owned utilities will be developed through Public Utilities Commission processes. Many of the frontier strategies that will carry the State towards its goal of achieving all cost-effective energy efficiency, some of which are mentioned above, are identified in the recently adopted California Long-Term Energy Efficiency Strategic Plan (see D.08-09-040 in R.08-07-011). The strategic planning process that the Public Utilities Commission and the Energy Commission are conducting is ongoing and will continue to identify and develop additional strategies for achieving the most energy efficiency savings possible.
In D.08-03-018 we recommended that the requirements for retail providers to procure electricity from renewable sources be increased above the current 20% RPS mandate, consistent with State policy and as expressed in the Energy Action Plan. However, we left open consideration of exact percentage requirements or deadlines, pending further analysis.
ARB's Draft Scoping Plan calls for California to obtain 33% of its electricity from renewable resources by 2020, and includes emission reductions based on this level. We concur with this commitment.
E3 modeled the resource costs associated with achieving a 33% renewables target statewide. E3's Accelerated Policy Case reflects a resource scenario in 2020 which includes 33% of electricity from renewable sources. The E3 modeling results indicate that achievement of 33% electricity from renewables would reduce GHG emissions in 2020 by an additional 12.8 MMT more than the current 20% RPS mandate, a larger reduction than any other electricity sector emission reduction measure. E3 estimates that these reductions may come at an average incremental cost of $133 per ton.
As discussed below, a number of parties have demonstrated that model results regarding renewables in both the Reference and Accelerated Policy Cases are highly sensitive to input assumptions.
A number of parties comment on the advisability of mandating that 33% of California's electricity comes from renewables as part of our package of recommendations to ARB.
LADWP claims that a 33% renewables mandate should be a "foundational strategy in achieving AB 32's goals" and CEERT asserts that a 33% renewables mandate "must be an integral part of the electricity sector's responsibility for reducing GHG emissions." However, PG&E and WPTF argue that to endorse a 33% renewables requirement in this proceeding would be premature and unreasonable.
In general, opposing parties suggest that to establish an unreachable renewables target would increase costs to a level that might incite a backlash against AB 32. They argue that adequacy of supply, availability of transmission, and integration concerns should be assessed before making 33% renewable electricity mandatory. PG&E and DRA argue that program set-asides should only be considered if a GHG abatement measure is low cost and other market failures exist, and that a 33% renewables mandate does not pass this test. WPTF cautions that increasing the renewables mandate to 33% would make it harder for other cheaper GHG control technologies to compete.
Several parties opposing a 33% renewables mandate state that the economic modeling by E3 supports their view, pointing to the incremental cost found by E3 of $131 per ton of GHG emissions saved by electricity from renewables. Furthermore, PG&E believes this number may be an understatement, asserting that the cost assumptions used in the 33% renewables scenario did not include costs of storage, ramping, regulation, over generation, and backup dependable capacity.
Different parties suggest that the public policy debate and technical evaluations needed to determine ability and appropriateness of increasing the RPS mandate above 20% would be very complex and should not be hurried (SMUD, DRA). In addition, SMUD argues that, because increasing the use of electricity from renewables would have a variety of benefits and costs, not just GHG reductions, it should be considered in a broader forum than this rulemaking.
Most commenting parties recognize the continued existence of significant barriers to renewable development in the State which will not be easily resolved. Parties arguing in favor of a 33% mandate, however, suggest that these barriers justify the need for an accelerated mandate.
More specifically, parties supporting a 33% renewables mandate suggest that:
· Such a policy statement would help build the certainty needed to encourage investor confidence that an aggressive renewable build-out will be supported by State policy (NRDC/UCS/GPI, CEERT, CalWEA/LSA).
· A higher renewables mandate would focus the efforts of government, utilities, and industry to overcome the transmission, siting, and other market barriers to developing electricity from renewables in the State (NRDC/UCS/GPI, CEERT).
· A higher renewables mandate would mitigate consumers' exposure to natural gas price risk likely to come as demand for natural gas intensifies and supply diminishes (NRDC/UCS/GPI, CEERT, Environmental Council).
· Pricing signals sent by a cap-and-trade program alone would be insufficient to ensure coordinated effort and achieve the penetrations of renewables desired (CalWEA, GPI, CEERT, SMUD, LADWP).
· A 33% renewables by 2020 mandate may be easier to meet than the current mandate of 20% RPS by 2010 (GPI).
CalWEA/LSA state that, "A comprehensive approach to renewables is fundamentally important if they are to play a significant part in GHG reduction. Renewables are a capital-intensive industry with long-term planning needs, both for the facilities themselves and the transmission infrastructure necessary to support them. It is unrealistic to expect the substantial investment needed for renewables to exceed the current 20% target based on a brand new pricing signal from a yet-to-be established cap-and-trade system, which, based on the experience of other markets, is certain to be somewhat volatile in its fledgling years." (CalWEA/LSA Comments, p. 2.)
Several parties supporting a 33% renewables mandate disagree with the cost assumptions used in the E3 model. In particular, they assert that E3 overestimates the cost of 33% renewables, by overestimating the cost trajectories of renewable technology (Environmental Council, CalWEA/LSA, CEERT, Solar Alliance, LADWP), underestimating the costs of natural gas (Environmental Council, CalWEA/LSA, CEERT, Solar Alliance, LADWP), and ignoring the potential risk of natural gas price volatility (NRDC/UCS, Environmental Council).
NRDC/UCS assert that, after making a number of changes to the model's input assumptions in these areas, the incremental costs of the 33% measure could reasonably be reduced to $45/ton. NRDC/UCS state that "at a natural gas price of approximately $13.50/MMBTU the 33% RPS/High-Goals EE scenario does not cost any more than the reference scenario. At natural gas prices of $14/MMBTU and higher, the 33% RPS/High-Goals EE scenario actually results in lower total costs. ... At gas prices above $14/MMBTU the cost of carbon is negative. ...[T]hese illustrative calculations are made using E3's own input assumptions, which, as discussed in the modeling section below, are highly conservative with respective to renewable energy cost and performance. Using more reasonable assumptions for these factors would reduce the `break-even' natural gas price to a much lower amount." (NRDC/UCS Comments, p. 9.)
In D.08-03-018, we reaffirmed our support for requiring retail providers of electricity to deliver more than 20% of their electricity from renewable sources in the future. We remain committed to additional renewable energy in California; renewable build-out is a keystone element of meeting AB 32's 2020 goal, as well as the State's longer-term 2050 goal. In the 2008 Energy Action Plan Update, we committed to "evaluate and develop implementation paths for achieving renewable resource goals beyond 2010, including 33% renewables by 2020, in light of cost-benefit and risk analysis, for all load serving entities." Further, as mentioned earlier, the ARB's Draft Scoping Plan calls for achieving 33% renewables based on Governor Schwarzenegger's call for 33% of the State's electricity to be provided by renewable resources by 2020, and includes emission reductions based on this level. We pledge to use our best efforts and to support the efforts of others to achieve 33% renewables by 2020.
Renewable mandates will 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. Further, E3's estimated average cost of obtaining 33% of electricity from renewables statewide, $133 per ton, is much higher than the carbon prices seen in other markets such as the European Union Emission Trading Scheme or the Regional Greenhouse Gas Initiative. Therefore, we do not believe that a cap-and-trade market alone will result in 33% renewables, and additional policies are necessary. In addition, renewable energy provides important environmental and other co-benefits, including reducing other non-GHG pollutants, when sited in California, providing further justification for policies specifically encouraging renewables.
We know from our continued implementation of the current 20% RPS requirement by 2010 that significant implementation barriers exist to the continued deployment of renewable energy in California. There are many sources of risk for project deployment, including uncertainties associated with the continuation of federal production/investment tax credits, availability of transmission, siting, and permitting issues. We agree with the comment in ARB's Draft Scoping Plan that program complexity is another challenge that must be addressed.29 We commit to work actively with other government agencies to overcome these barriers.
AB 32 requires that the emission reduction measures undertaken to achieve its target be both cost-effective and technically feasible. The 2007 Integrated Energy Policy Report states that, "scenario analysis indicates that... aggressive cost-effective efficiency programs, when coupled with renewable development, could allow the electricity industry to achieve at least a proportional reduction, and perhaps more, of the state's [carbon dioxide] emissions to meet AB 32's goals." It notes that "meeting the 33% goal in 2020 is feasible, but only if the state commits to significant investments in transmission infrastructure and makes some key changes in policy." Initial analyses of the cost-effectiveness of a 33% renewable mandate have been undertaken,30 including by E3, and continue to be developed. Cost-effectiveness studies must incorporate existing State policies and priorities, including the loading order for meeting the State's electricity demand, as well as the need to set a course to achieve the longer-term GHG emission reduction targets set by the Governor of 80% reduction of GHG emissions below 1990 levels by 2050. The social costs and benefits of mitigating climate change must also be taken into account.
E3's analysis provides preliminary estimates of the potential costs of achieving 33% renewables. However, before discussing E3's analysis further, we first note an error in PG&E's assertions about the E3 modeling assumptions for renewables. PG&E is incorrect in stating that E3 did not account for the costs of integrating renewable power onto the grid, including costs such as ramping, regulation, and backup dependable capacity. E3 did, in fact, estimate and account for those costs.
Several parties utilized the E3 GHG Calculator to support their positions, either for or against mandating 33% renewables. This illustrates that there continues to be a great deal of uncertainty regarding the assumptions underlying a 33% renewable mandate. Factors contributing to this uncertainty include: (1) the proportion of intermittent to firm or baseload renewables developed for the State's renewable energy goals and voluntary REC market; (2) retirement of existing generation due to once-through cooling requirements and other variables; (3) generation changes made to the fossil-fuel generators' ramping capabilities over the next 12 years; and (4) changes made to the amount of regulation support, short-term and long-term storage, and the integration of Smart Grid technologies, among other factors.
While a number of parties, including NRDC/UCS, assert that E3 overestimates the costs of renewables and that renewable technology and installation costs should decline over time, others such as PG&E believe that the costs of integrating this level of renewables into the electricity system are understated.
We believe that E3's assumptions regarding the costs of renewables are reasonable. On the one hand, theory and some historical experience suggest that costs of renewable technologies should decline over time. E3 did not include estimates of this effect because it is speculative and uncertain. On the other hand, E3's assumptions also do not reflect that contract prices for successful renewable projects have increased in recent years, and in some cases far exceed the cost assumptions in E3's model. All of this illustrates the significant uncertainty associated with modeling the costs of achieving 33% renewables, and the speed with which necessary system improvements can be achieved.
Using current estimates, E3's analysis suggests that the average costs for new renewable generation projects may reach approximately $130 per ton of GHG emissions abated. This is significantly higher than the price for carbon in any market currently operating (the European Union Emission Trading Scheme, or the initial auctions held for the Regional Greenhouse Gas Initiative in the Northeastern states) and would represent a significant cost to California ratepayers.
Significant work is underway in California and elsewhere to better understand what it will take to achieve 33% renewables. The Commissions, along with the CAISO, are participating in the Renewable Electricity Transmission Initiative. As part of that initiative, additional cost estimation is occurring. The CAISO may need to do additional analysis to fully understand the grid management changes, improved forecasting tools, and changes to the electricity grid infrastructure needed to integrate 33% renewables into the California electricity system.
In addition, the Public Utilities Commission intends to develop a 33% renewables analysis in the long-term procurement proceeding, adhering to four guiding principles: (a) ensuring reliability, (b) ensuring the lowest reasonable rates by continuing to encourage the development of functional competitive markets (or other market structures), (c) adhering to the Energy Action Plan loading order, and (d) anticipating AB 32 constraints on investor-owned utilities' electricity portfolios.31 With these guiding principles, the 33% analysis should assess yearly renewables targets based on an implementation assessment of feasibility and a valuation of different generation characteristics including peaking, dispatchable, baseload, firm, and as-available capacity of renewable projects. We expect the 33% analysis to further inform our understanding of the cost and feasibility of achieving even higher renewables levels.
As with energy efficiency discussed above, a mandatory utility renewables program may be the best way to achieve the bulk of needed renewables investments, but we may also wish to explore other innovative options to achieving additional renewables in the State. In addition to RPS and the California Solar Initiative discussed below, there may be other ways to encourage innovation in renewables, such as through voluntary private sector investment and additional distributed renewables programs. We support expanding the RPS, but also advocate additional policies and mandates to achieve at least 33% renewables for California, which may be met through a variety of approaches including voluntary investments. Additionally, the existing RPS statutes and regulations should be reexamined to determine if there are opportunities to reduce complexity and make changes that will help the State achieve its GHG reduction goals at the lowest possible costs.
We expect that ARB will conduct additional analysis of GHG mitigation options and costs in other sectors of the economy. To date, all of the ARB analysis released in association with AB 32 has addressed only electricity sector costs. In order to meet the cost-effectiveness requirements of AB 32, the costs of reducing GHG emissions through renewable investment should be compared to the costs of abatement in other sectors, including industry and transportation. As the ARB Scoping Plan and AB 32 implementation process progresses, we expect to learn more about the potential costs of GHG reductions in other sectors relative to the costs of measures that may be undertaken in the electricity sector.
We recognize that meeting California's longer-term 2050 GHG reduction goals will require significantly reducing the GHG footprint of the electricity sector. Policies and mandates that achieve 33% of California's electricity from renewables by 2020 are an important step in achieving this transformation, even if renewable energy investments represent relatively higher marginal cost abatement opportunities in the near term.
NRDC/UCS and other parties may be correct that the costs of at least some renewable technologies may decline between 2010 and 2020. However, we cannot project this outcome with any certainty in 2008.
Further, there are other reasons to support a 33% renewables mandate besides GHG emissions mitigation as required by AB 32. These include fuel diversity, economic development benefits for California, and air quality improvement in California, to name a few. These reasons may support a higher renewables mandate or a different program design than would be found reasonable for GHG reduction alone. These issues also require further analysis and discussion among policymakers.
For all of these reasons, we support requiring that all retail providers of electricity deliver 33% of their electricity from renewable sources by 2020. We also support ongoing analysis of the implementation path needed, the actions we can take to help ensure success, and the potential costs and benefits of renewables in the context of AB 32.
In response to comments on the proposed decision, we address the treatment in a cap-and-trade program of RECs and "null" power, the electricity from renewable sources that may be sold separately when RECs have been unbundled from the electricity. The Public Utilities Commission has not authorized load serving entities to use tradable RECs for RPS compliance, but expects to consider the possibility in an upcoming decision in R.06-12-012. In anticipation that tradable RECs may be authorized in the future, the Public Utilities Commission stated recently in D.08-08-028 that,
[O]nce a REC is used for RPS compliance (either before or after a GHG cap is imposed), the REC cannot also be used as a GHG emissions offset. In addition, once a GHG cap is imposed, RPS-eligible generation subject to a cap never avoids emissions. The "avoided emissions" will continue to be included in the REC, but the avoided emissions will be zero; the balancing GHG emissions value of the null power will therefore also be zero. Thus-assuming that ARB adopts this analysis-our characterization of the REC will not require any RPS-eligible generation with zero GHG emissions to need allowances when delivered to the California grid [footnote omitted]. (D.08-08-028, mimeo. at p. 24.)
We recommend that ARB rely on and adopt the above analysis and conclusions in D.08-08-028, i.e., that RPS-eligible generation with zero GHG emissions would not need allowances when delivered to the California grid, regardless of whether RECs have been unbundled from the electricity such that the electricity is delivered as null power.
The analysis in D.0-08-028 did not address a scenario in which Public Utilities Code Section 399.16(a)(3) is modified to allow use for RPS compliance of unbundled RECs from electricity not delivered to the California grid. If such a revision occurs, the appropriate treatment of unbundled RECs from electricity generated in an uncapped state and not delivered to the California grid may require further consideration.
While renewables and energy efficiency are by far the most effective and expansive emissions abatement opportunities for the electricity and natural gas sector currently available, other potential emission reduction measures have been addressed by E3 modeling, ARB Scoping Plan development, and party comments.
In its modeling of GHG scenarios, E3 included two other major areas of GHG reduction: rooftop photovoltaic installations realized through the California Solar Initiative, and increased CHP installations.
For rooftop photovoltaics, while E3's Reference Case includes the level assumed to be in the Energy Commission's load forecast (847 MW), the Accelerated Policy Case reflects the achievement of the California Solar Initiative program goal of 3,000 MW. The E3 modeling results indicate that achieving the California Solar Initiative goal would reduce GHG emissions in 2020 by an additional 1.7 MMT CO2e compared to the Reference Case.32
For CHP, while the Reference Case reflects what is assumed to be in the Energy Commission's load forecast (292 MW behind-the-meter CHP and no new CHP over 5 MW in size), the Accelerated Policy Case reflects the achievement of approximately 1,600 MW of new small CHP (smaller than 5 MW) and 2,800 MW of new large CHP (larger than 5 MW). The E3 modeling results indicate that achieving this CHP goal would reduce GHG emissions in 2020 by an additional 4.9 MMT compared to business as usual.
The ARB Draft Scoping Plan includes one additional emission reduction measure that was not addressed in the E3 modeling: solar hot water heater installations. Solar hot water is included in the Draft Scoping Plan as a way to reduce natural gas use in homes and businesses. The Draft Scoping Plan assumes the installation of 200,000 solar water heating systems by 2020, saving 26 million therms of natural gas per year (a goal set forth in AB 1470, Huffman, Chapter 536, Statutes of 2007). The Draft Scoping Plan finds that achieving this goal would result in 0.1 MMT of GHG reductions.
NRDC/UCS and SCE raise solar hot water heating as a measure worthy of consideration, particularly if the natural gas sector is not part of a cap-and-trade program initially, as recommended in D.08-03-018.
PacifiCorp suggests that California consider incentives for utilities to pursue grid applications that address electrical losses, electricity storage as an enabling technology for increasing utility scale renewable penetrations, and Smart Grid technology to accommodate distributed renewable resources and demand response. In addition, PacifiCorp suggests that California consider providing incentives for carbon capture and sequestration, and for repowering and retirement of high GHG-emitting fossil-fueled plants.
NRDC/UCS suggest a number of measures to reduce GHG emissions through efficiency gains, including time-of-sale energy efficiency requirements, appliance feebates, and water-use efficiency. In addition, NRDC/UCS suggest biomethane as a powerful abatement opportunity in the natural gas sector. According to their estimate, biomethane has the potential to save 7.2 MMT of GHG emissions by 2020 from dairies alone, with further potential savings from wastewater treatment facilities.
In this section, we address each suggested additional mandatory emission reduction measure in turn and suggest an appropriate venue for additional analysis or policymaking. If a suggestion is not addressed, it is either because the measure was too vague or, in some cases, because an appropriate venue does not yet exist. We remain open, however, to ongoing suggestions for additional emission reduction measures that may be implemented to help support the AB 32 goals.
Rooftop Solar Photovoltaics
California already has an aggressive effort to encourage deployment of customer-sited photovoltaics, in the form of the Public Utilities Commission's California Solar Initiative and the Energy Commission's New Solar Homes Partnership. In those programs, we have set a goal of 3,000 MW of installed solar photovoltaic capacity in California by 2017. We believe this target is appropriately aggressive and do not suggest amending it at this time. However, should we decide to pursue additional initiatives for solar photovoltaics, our separate proceedings on these programs are the appropriate venue for such consideration. At the Public Utilities Commission, the California Solar Initiative rulemaking is R.08-03-008. The Energy Commission is responsible for policymaking for the New Solar Homes Partnership.
Solar Hot Water
We agree with ARB, NRDC/UCS, and others that solar hot water is worthy of inclusion in the Scoping Plan, with potential to go beyond current mandates. The Public Utilities Commission is in the process of implementing AB 1470 (Huffman), which requires consideration of the results of a pilot program in San Diego before implementing additional solar hot water heating incentives. Results of that evaluation are expected later this year in R.08-03-008.
Combined Heat and Power
In this proceeding, we address two fundamental questions about CHP systems. One question is how to regulate GHG emissions from CHP; this issue is discussed in Section 6 below. We address here the other question about CHP: whether and how to treat it as an emission reduction measure, as proposed in the Draft Scoping Plan.33
Properly designed and sited CHP systems can provide efficient co-generation of electricity and thermal heat. In addition, on-site generation avoids electricity transmission and distribution losses, thus avoiding more fuel consumption for the generation of electricity. Because it reduces the consumption of fossil fuels, CHP can reduce GHG emissions. Types of CHP systems are described in more detail in Section 6.1 below.
Parties were asked to file comments on whether CHP should be considered to be an emission reduction measure, and whether there should be efficiency requirements in order for CHP systems to be considered an emission reduction measure. The parties largely support the concept of encouraging additional CHP as an emission reduction strategy, as long as CHP units are efficient and sized appropriately. However, some parties raise certain concerns about treating CHP as an emission reduction measure.
PG&E contends that there will be a market for more efficient, less GHG-intensive electricity and, as a result, that there is no need to classify CHP as an emission reduction measure. The logic behind PG&E's conclusion is that the market will inherently favor CHP's less GHG-intensive electricity.
Other parties, including EPUC/CAC and CCC, argue to the contrary that GHG regulation might create disincentives for CHP facilities whose GHG emission rate is higher than the average emission rate of the local utility's electricity portfolio. GHG costs embedded in a utility's retail electricity rates will depend on the utility's owned resources, its degree of reliance on the wholesale electricity market, and the carbon costs that are included in wholesale electricity rates. It is possible that a CHP facility's per-MWh compliance costs would be higher than the averaged compliance costs embedded in the utility's retail rates even though the CHP's emission rate might be lower than the emission rate of marginal generation sources used by the utility. In such circumstances, emissions would increase if the CHP owner chooses to purchase electricity from its local utility rather than produce electricity on-site, making attainment of GHG reduction goals more difficult. This problem is not unique to CHP, but could arise for any distributed generation facilities.
Both PG&E and SCPPA assert that classification of CHP as an emission reduction measure would result in a de facto subsidy. A related comment was filed by DRA, which supports including CHP as an emission reduction measure but cautions against setting a specific target level without careful consideration of the cost. As stated elsewhere in this decision, we agree that cost-effectiveness is a key criterion in the establishment of emissions reduction measures, and it is critical in setting targets going forward. DRA's point is well taken that the cost-effectiveness criterion will act as a safeguard against over-building the amount of CHP in the State; it will help ensure that there will be an increase, but that it will be done in a cost-effective manner. However, the assertion that classification of CHP as an emission reduction measure creates a subsidy is incorrect. We may, however, wish to consider incentives for CHP, if we determine that the cost-effective and economically-rational level of CHP investment in the State is not occurring due to identified barriers. This should be considered in another venue, as discussed below.
Most other comments about CHP as an emission reduction measure center around the idea of encouraging efficient CHP. We do not have enough information, however, to establish an overall level or method that should be used to achieve this efficiency. While encouraging a certain level of efficiency is an important policy goal, we do not believe it is necessary to set a particular threshold at this time.
Overall, we support the identification of CHP as an emission reduction measure, as already included in ARB's Draft Scoping Plan. This is primarily due to the ability of CHP to reduce overall GHG emissions by producing two products (heat and electricity) with one fuel input. Classifying CHP as an emission reduction measure would complement the market demand for less GHG-intensive electricity. As with other forms of efficiency, there may be barriers to the adoption of CHP that would prevent achievement of optimal levels of CHP through a market-based system.
The Draft Scoping Plan anticipates a level of 32,000 GWh of new CHP, which would lead to emission reductions of 6.9 MMT CO2e in 2020. This level translates to the installation of 4,000 MW of new CHP with an assumption of a capacity factor of 85%.
We support the treatment of CHP as an emission reduction measure and the goal to encourage cost-effective, fuel-efficient, and location-beneficial CHP. Several existing activities will help inform the amount of new and efficient CHP that California can expect. In compliance with AB 1613, the Public Utilities Commission recently opened a new rulemaking, R.08-06-024, which is addressing the policies and procedures for purchase of electricity from small CHP less than 20 MW. The Energy Commission plans to open a proceeding in early 2009 to develop operational standards and guidelines for AB 1613-eligible customer-generator CHP systems. These guidelines will ensure that new CHP systems that are eligible under this law meet all operational, fuel efficiency, and emission standards intended by the Legislature. These guidelines will apply to new CHP facilities in both the investor-owned and publicly-owned utility service territories. In addition, the recent Qualifying Facility decision issued by the Public Utilities Commission in September 2007 (D.07-09-040) applies to some CHP contracts with utilities.
Unlike other measures discussed in this section, there is not a strong policy framework in place for the development of new CHP and the evaluation of existing CHP. The best policy tools available to both investor-owned and publicly-owned utilities to encourage efficient CHP are not yet clear.
We are persuaded that further investigation is necessary regarding market and regulatory barriers for CHP. There is a clear need for a broader look at CHP policy (both for new and existing units, at various capacity sizes). The Public Utilities Commission intends to establish a new rulemaking to address these and other issues related to CHP in order to help maximize cost-effective GHG reductions from CHP. This rulemaking will explore removal of existing barriers to deployment of CHP and, on that basis, the setting of realistic targets for CHP contributions to the AB 32 goal. In addition, the Energy Commission plans to explore options with the publicly-owned utilities to accelerate CHP installation incentives that some publicly-owned utilities have already initiated.
Time-of-Sale Energy Efficiency, Appliance Feebates, Water Use Efficiency
NRDC/UCS suggest several efficiency initiatives to help increase savings of energy and water. These additional energy efficiency measures should be considered by both Commissions and, where advisable and within our jurisdictions, directly implemented. Some highly significant measures, such as time-of-sale efficiency upgrades, may need to be addressed by ARB or the Legislature. Regarding water conservation and efficiency, the Public Utilities Commission currently has a water conservation investigation (I.07-01-022). We also anticipate continuing to work with the Department of Water Resources and the State Water Resources Control Board on additional water efficiency measures as the Scoping Plan process goes forward.
4.2. Reliance on Mandates and Markets
Desired emission reduction outcomes can be achieved using a number of distinct policy approaches. Because ARB is considering a market-based cap-and-trade program inclusive of the electricity sector as part of its AB 32 implementation strategy, in conjunction with regulatory mandates, an important question for the electricity sector concerns the interaction of GHG reductions through direct mandatory or regulatory control measures with voluntary reductions, including those claimed through the potential market-based cap-and-trade program under consideration at ARB.
We in D.08-03-018 and ARB in its Draft Scoping Plan recognized the role for both mandatory measures and market-based approaches. However, the level at which mandates would be set and the way in which mandatory measures would interact with the potential cap-and-trade program have yet to be addressed. This section describes opinions of the parties as expressed in this proceeding.
Most parties agree that existing regulatory mandates have served as a successful means of slowing the rate of growth of GHG emissions within the electricity and natural gas sectors to date. Parties have differing opinions, however, regarding the degree to which codes and standards, efficiency and solar programs, and RPS requirements should be expanded beyond current levels in order to achieve deeper reductions as required by AB 32.
Several parties assert a strong view that any additional reductions in the electricity sector to achieve reductions under AB 32 should be driven solely by a cap-and-trade market. Parties in support of this approach argue that such an approach would ensure that any further reductions from the sector would be cost-effective in the context of the statewide effort and relative to costs from other sectors (PG&E, Morgan Stanley, SCE, SDG&E/SoCalGas). A number of parties also point out that the more mandatory measures that are adopted, the less benefit there would be from a cap-and-trade system (SDG&E, DRA, TURN).
Other parties in support of a cap-and-trade-only approach to achieving additional reductions assert that, because a market rewards over-compliance and innovation, greater levels of emissions reductions would be realized more quickly by way of a cap-and-trade program than by using a programmatic or mandatory approach (Calpine, WPTF, SCE).
In addition, PG&E urges that the Commissions be extremely careful in assuming that further reductions will come from direct energy efficiency and renewable programs other than those programs already in place, because meeting existing targets has been challenging even at current levels.
A second group of parties advocate that the electricity sector should be left out of a cap-and-trade system entirely. Instead, they argue that the sector would be better-suited to pursue its emission reduction responsibilities by way of programmatic mandates only. This issue was addressed in D.08-03-018, in which we recommended a multi-sector cap-and-trade program including the electricity sector. However, we summarize these comments here, for completeness, with the benefit of new information and analysis by E3 as well as the issuance of the Draft Scoping Plan by ARB. These parties base their recommendation on the following arguments:
· A market-based approach would only add costs to overall compliance, with very limited added environmental benefit (SCPPA, LADWP, CUE).
· Allowance prices would have to be extremely high before a market would cause changes in dispatch and otherwise bring about incremental GHG reductions above aggressive policy mandates in the electricity sector (SCPPA, LADWP, CUE, IEP, TURN).
· Leakage and/or contract shuffling would negate any benefits of reduced emissions from imported coal in a California-only cap-and-trade system (TURN).
In most cases, parties draw heavily on the modeling results provided by E3 to argue that mandates can effectively achieve emission reduction goals within the sector and that the market would be a costly means to achieve incremental reductions within the sector. For instance, SCPPA, SDG&E/SoCalGas, LADWP, and SMUD point out that, according to E3's results, the electricity sector could meet the goal of 1990 emissions levels by 2020 through existing programmatic mandates including the 20% RPS goal and energy efficiency programs. NCPA asserts that the electricity sector is already below the 1990 benchmark level. Further, SCPPA points out that, according to E3's results, "nearly no emissions reductions would be derived from participation in a cap and trade program until very high levels of allowance prices -- $100 to $150/ton CO2-are reached." As discussed below, a number of parties suggest in reply comments that the conclusions reached by these parties relying on E3's results are flawed.
A third set of parties does not favor one approach over the other; they argue that it is not an "either or" scenario. Instead, they view mandatory regulations and market mechanisms as two complementary policy instruments with added value when used in concert. They support the conclusion in D.08-03-018 that a combination of additional mandates and a cap-and-trade program should be used to achieve incremental reductions within the sector.
Parties in support of this combined approach offer the following reasoning:
· While the GHG price established by a cap-and-trade program is essential, it would not overcome the various non-price market barriers that other regulatory programs can more effectively address (NRDC/UCS, GPI).
· While mandates can drive progress toward broad emission reduction targets, a cap-and-trade program would provide a back-stop and would capture any resulting shortfalls in expected emission reductions due to higher load growth or delayed RPS development (NRDC/UCS, PG&E, WPTF).
· While mandates can be effective in deploying existing technology, a cap-and-trade program would offer distinct benefits by accommodating and rewarding emerging GHG control technologies not embodied by current mandates (WPTF).
This position is supported by a number of reply comments rebutting the arguments of parties that utilize E3 model results to argue for a market-only or mandate-only approach.
PG&E and WPTF assert that, because the E3 model results are highly sensitive to input assumptions and because slight increases in load growth would yield higher emissions levels than suggested by E3's Reference Case, the Commissions should reject parties' conclusions based on E3 Reference Case results that a cap-and-trade program and other compliance options will be unnecessary. PG&E in particular offers an alternative reference case based on a set of modified assumptions which indicates that 2020 reference case emissions would be above 1990 levels.
Similarly, both PG&E and WPTF argue that conclusions based on E3's model that a cap-and-trade program would impose extra costs with no GHG benefits are flawed. They assert that cost efficiencies from a cap-and-trade program would stem from a number of factors that are unaccounted for in the model, including the ability to harness cross-sector abatement opportunities and innovation incentives provided by the system, which could drive the discovery of unforeseen opportunities for compliance by entities within the sector. These parties argue that, while these factors cannot be modeled quantitatively, they are qualitatively understood as better utilized by market instruments than by programmatic approaches and mandates.
On the other side, NRDC/UCS argue that conclusions based on E3's model that additional mandates are not cost-effective are flawed. NRDC/UCS submit that determination of these measures' cost effectiveness depends on there being low-cost abatement opportunities in other sectors, and sufficiently many to meet the cap before pursuing such aggressive in-sector measures. They assert that we cannot make judgements based on E3's model regarding the availability of lower-cost emission reduction measures in other sectors, and caution against the "false hope" of assuming their availability. While in support of a cap-and-trade program covering the electricity sector, they believe that a majority of emission reductions in this sector should be achieved through programmatic and regulatory measures. They suggest that any reduction in the effort to achieve significant direct, in-sector emissions reductions through the expansion of existing mandates would defer urgently needed investments in these areas, thereby increasing the overall cost of AB 32 compliance.
In D.08-03-018, we recommended that ARB consider both mandatory/regulatory measures and a multi-sector market-based cap-and-trade program for the electricity and natural gas sectors in California. Nothing in parties' comments or in the E3 modeling work convinces us that we should reconsider our support of both additional mandatory measures, as discussed above, and a well-designed cap-and-trade system.
However, whether a cap-and-trade system achieves its desired results is highly dependent on its design. The E3 modeling results reveal specific areas of concern where careful monitoring and verification will be needed to ensure that the cap-and-trade system functions as anticipated. In particular, these include monitoring to ensure that the cap-and-trade program does in fact achieve real reductions in emissions at reasonable cost and that significant revenue shifts unrelated to emission reductions between customers of different retail providers, or from retail providers to generators, are avoided.
Since the issuance of D.08-03-018, the Western Climate Initiative draft design of a regional system that would link state-specific cap-and-trade programs throughout the Western United States has developed rapidly. Draft design principles were issued on July 23, 2008 that target an opening date of January 1, 2012 for the regional linked system. Given this, we strongly believe that partnership and linkage with other states in the Western Climate Initiative for the cap-and-trade system is critical in order to remove or mitigate the challenges and limitations of a California-only approach.
While the opportunities for emissions reductions within the electricity sector are bounded by economic and jurisdictional constraints, it remains within California's best interest to act aggressively and proactively to begin a large-scale transformation of its electricity infrastructure and demand patterns. Taking into account the lack of a national program at this time and the State's requirement to implement AB 32, we have carefully considered the best interim steps that California's electricity and natural gas sectors can take to meet the AB 32 requirements, and to support participation in a linked Western Climate Initiative system, while preparing to move toward a nationally and ultimately internationally integrated program.
In the near term, the cap-and-trade program can serve to supplement other policy tools in place by providing a backstop, in case the reductions from the mandatory programs do not fully materialize as expected. In addition, as we stated in D.08-03-018, a cap-and-trade program will likely provide a relatively small incremental portion of the overall emission reductions needed to meet the 2020 limit, above emission reductions achieved due to existing and expanded mandatory measures.
In the later years of AB 32 compliance, it is likely that a broader national market will be in effect, and GHG emissions abatement technology will have developed significantly. Under these circumstances, a market framework may become the preferred means to motivating increased emissions reductions throughout the economy.
If we were to pursue goals only through mandates, incentives, and other programmatic methods, the price effects could be inconsistent. Utility customers would pay for the costs of the recommended measures in ARB's Draft Scoping Plan. However, without a cap-and-trade program or carbon fees, there would not be a price incentive for the fossil-fired portion of the electricity sector to become more efficient. There would be no market to reward clean-burning fossil technologies or to provide incentives for the incremental efficiency changes that can be made in a host of fossil fuel-using facilities. Enlisting the generation community in the effort to reduce emissions makes sense as a policy tool. Utility customers would likely pay most of the costs of energy efficiency, renewable, and CHP programs, although with carbon fees or allowance revenues under a cap-and-trade program, those costs can be allocated more broadly in the economy.
As a result, we reiterate the recommendation in D.08-03-018 that the electricity sector pursue a two-pronged approach to achieving emission reductions using both current and expanded mandates, under which programmatic strategies dominate in the short term, and a market-based approach, which would provide increasingly powerful incentives for emission reductions over time, allowing reductions to be achieved in the most cost-effective manner possible.
E3 modeling confirms that, through aggressive regulatory measures, the electricity and natural gas sectors can reduce emissions substantially between now and 2020, provided that utility programs are extended in a binding manner to the publicly-owned utilities, and provided that incremental building and appliance standards, as well as new innovative program design methods, are enacted.
Furthermore, as evidenced by the modeling, many of our targeted technology solutions - central station renewables, rooftop solar photovoltaics, and carbon capture and storage - arguably would not occur at any reasonably large scale if we rely only on market forces unless the price of carbon rises to some point significantly above $60 per ton. If we were to use a market-based approach alone, we may not be able to keep program costs low or support market transformation of desired technologies.
Accordingly, our recommendation in D.08-03-018 that California pursue a two-pronged approach to GHG regulation in the electricity and natural gas sectors - continuation of regulatory mandates designed to accelerate development and deployment of specific low-carbon technologies in the near term, and a market-based approach to leverage the potential for discovery of emission reduction measures currently unknown to regulators-in order to achieve incremental emissions reductions at least cost and over the longer term is supported by E3's analytics.
We recognize that achieving the goals set by current and expanded mandates will require significant expenditures by utilities and likely will result in increased rates for utility customers, although reductions in customer energy usage due to energy efficiency achievements may allow average customer bills to decrease at the same time. Significant co-benefits for California may also be achieved. The success of these mandatory programs will require dedication, creativity, and will but, once achieved, will result in significant contributions to the state's overall GHG reduction goals. It is important to recognize that some delays or other failures may occur for some of the programs considered here, including both the regulatory mandates and the cap-and-trade program. However, the overlay of a cap-and-trade mechanism on mandatory programs serves as an insurance policy to make sure the emission reductions occur, and to supplement enforcement mechanisms by providing additional economic benefits for achievement of the mandates. Similarly, the incorporation of the mandates provides additional assurance that the overall program will deliver tangible, near-term results.
We acknowledge potential downsides to our two-part strategy, as follows. First, any significant shortfall in meeting aggressive mandates could result in upward pressure on allowance prices in a cap-and-trade market, due to the fact that additional allowances may be needed by entities with compliance obligations on short notice due to the failure of mandates. By the same token, unanticipated problems in the cap-and-trade market, such as larger-than-expected shifts of revenue between retail providers without productive emissions reductions, larger-than-expected windfall profits, and costs incurred by retail providers due to unexpectedly high or volatile allowance prices may undermine the ability of some retail providers to achieve their goals. We emphasize the need for continuous monitoring and updating of all programs implemented in the electricity sector in support of AB 32, and their interactions, in order to ensure that we achieve the goals of AB 32.
4.3. Contribution of Electricity and Natural Gas Sectors to AB 32 Goals
This proceeding was scoped to include making recommendations to ARB regarding the total contribution that the electricity and natural gas sectors can reasonably make toward meeting the AB 32 emissions reduction goals, and the setting of annual GHG emissions caps for the electricity and natural gas sectors.
There are a number of bases upon which ARB could allocate GHG reduction responsibility among sectors, including the relative cost-effectiveness of identified emission reduction measures in the individual sectors and the potential impacts on consumers, including rate impacts for electricity and natural gas customers, of varying levels of emission reductions responsibility among the sectors.
It is challenging at this point to determine the cost-effective level of electricity and natural gas sector emission reductions because we have very little sense of the abatement opportunity and costs in other sectors.
If there is a multi-sector cap-and-trade program, sector-specific emissions caps would not be set. We expect that there would only be a single emissions cap that would apply to the aggregate emissions from all the sectors under the cap. In this multi-sector scenario, if allowances were administratively allocated, ARB would still need to determine how many allowances (or how much allocation value) would be allocated to the electricity and natural gas sectors, assuming that ARB's cap-and-trade program design includes the allocation of allowances or allowance value among the sectors. ARB policies regarding both the scope of mandated emission reduction programs and the allocation of GHG emission allowances or allowance value to each sector would determine the extent to which individual sectors bear the cost responsibility of the emission reductions necessary to reach AB 32 goals. We discuss this in more detail below.
An important consideration regarding the appropriate level of emissions reductions from the electricity and natural gas sectors is the associated rate and cost impacts on utility customers. E3's modeling results provide some guidance on the relative rate and cost impacts of emissions reductions responsibilities of varying stringency within the electricity and natural gas sectors.
Several parties assert that there is no need to recommend annual caps or sectoral targets, based on their view that the market will determine cost-effective distribution of emission reductions among the sectors (WPTF, SCE, GPI). Other parties (SMUD, DRA, NCPA, MID, TURN) suggest that additional information is needed regarding the relative cost of abatement opportunities in other sectors, before the desirability of additional mandates or sectoral responsibility can be determined. CEERT and NRDC/UCS emphasize their view that allocation of responsibility to the sectors and annual cap recommendations are important aspects of our recommendations to ARB. IEP suggests that the sectors should bear responsibility proportional to their contribution to statewide emissions.
GPI anticipates that the electricity sector will be required to make reductions below 1990 levels, with proportional reduction requirements in excess of its proportion of contribution to statewide emissions. GPI suggests that sector caps should be treated as rough guidelines, used only for planning purposes and crafting policy measures, and distinct from AB 32's statewide mandate which is obligatory and absolute.
A number of parties comment on the trajectory of annual caps, including PacifiCorp, Dynegy, IEP and SCE. These parties suggest that cap setting should be gradual, in step with the lead times necessary for renewable and other investments to run their course, and should reflect the limited GHG abatement opportunities available to deliverers in the short term.
CMUA submits that the two Commissions should recommend principles, and ARB must implement regulations, that encompass an equitable proportionality of reduction obligations among the different sectors.
PG&E recommends that, in advising ARB regarding what the electricity sector emissions will be and the reductions expected from current programs, the Commissions should be mindful of communicating realistic levels and should not double count savings. PG&E believes that targets for California can be based on "stretch" goals, with agencies supporting technological innovation in the marketplace and research and development to reach those goals, rather than "command and control" mandates.
In addition, PG&E states that statutory criteria in AB 32 for setting emissions reduction targets should be applied to the annual emissions caps to be set for the 2012-2020 period. These include technological feasibility; economic efficiency; cost and rate impacts on consumers, businesses, and governments; and impacts on low income communities and ratepayers. PG&E suggests that the trajectory of emissions targets for 2012-2020 should take into account a rigorous and full peer- and public-reviewed economic model of the impacts of the targets on each sector of the California economy, including an assessment of abatement costs and availability of emissions abatement measures in each sector.
PG&E further submits that assumptions regarding the electricity generating resources that will remain in operation during the 2012-2020 period, including coal-fired and other high-emitting generating resources, should be evaluated in setting interim 2012-2020 targets for the electricity sector.
PG&E also states that the emissions trajectory should be gradual. It asserts that it will be many years before emissions reductions are achieved by new long-term capital investments. Citing an inability for energy consumption to change greatly in the short term, PG&E recommends that the emissions trajectory should allow for growth in the short term, followed by gradual reductions.
Finally, PG&E states that the allowance value apportioned to the electricity sector should be fair and should recognize the lengthy history of investments in energy efficiency and renewables. PG&E believes that electricity customers should not subsidize emission reductions in other sectors.
SDG&E/SoCalGas recommend that electricity and natural gas sector caps should be based on the mandatory measures ARB finds to be cost-effective, with the cap-and-trade program designed to provide the same level of reduction as would be projected to occur if ARB had adopted the mandatory measures that were deemed to be cost-effective. SDG&E/SoCalGas agree with PG&E that entities subject to the cap should not pay for any shortfalls in reductions in other sectors.
SMUD states that the Commissions are in the best position to determine what levels of renewables and energy efficiency are possible, and the cost-effectiveness of achieving those levels. SMUD emphasizes its view that, in considering whether to require the electricity sector to reduce emission below its 1990 levels, ARB must weigh the cost relative to reductions in other sectors.
According to CEERT, the Commissions should recommend to ARB specific cost-effective and prudent levels of energy efficiency and renewables to be obtained in the electricity sector. GPI, on the other hand, as summarized above, recommends that any identification of sector caps should be considered as rough guidelines only for planning purposes.
PacifiCorp and SMUD recommend that we defer any recommendations on sector responsibility or annual caps until we have a better sense of opportunities available in other sectors.
We agree with parties who suggest that the level of responsibility or "burden" under AB 32 should be proportional and fair to consumers in all sectors of the economy. However, defining what is fair or proportional is difficult particularly because, as noted by several parties, while we have a great deal of information about the opportunities and costs for GHG mitigation in the electricity sector provided by E3, we do not have equivalent information about the other sectors.
One approach would be to analyze the GHG mitigation cost curve for measures available in all sectors of the economy, and choose the least costly options such that the desired reductions are obtained, regardless of the sector(s) in which the emission reductions occur. This is similar to E3's analysis for the electricity sector, but would be performed on a multi-sector basis. A second approach, apparently being utilized by ARB, is to identify feasible or achievable measures and strategies available in each sector and choose some for adoption as regulations while allowing others to be achieved through a market-based approach, without prioritization based on relative cost-effectiveness. In either approach, it does not follow that the cost burden of each chosen mandatory measure should be borne within its own sector. Under a combined market-based and regulatory strategy, the responsibility for the cost burden can be separated from the obligation to reduce GHG emissions.
E3's analysis of potential emission reduction measures for the electricity and natural gas sectors represents the best available information upon which the Commissions can base a recommendation regarding emission reduction measures in these sectors. As discussed at length above, this analysis is subject to a great deal of uncertainty, but represents a significant advancement in our understanding of what is feasible in the sectors as well as the overall magnitude of potential costs.
The best use of the E3 results is to inform policymaking through highlighting differing outcomes across a range of inputs. We present below a scenario designed to represent a reasonable potential outcome, as analyzed by E3.
Section 3 above discusses in detail E3's assumptions and approach. We will not reiterate that discussion here, except to say that, on balance, we find E3's approach and analysis to be reasonable to inform our recommendations.
Figure 4-1 shows a reasonable scenario of potential achievable emissions reductions in the electricity sector compared to its historical emissions levels. In this scenario, all emission reduction measures contained in E3's Reference Case and Accelerated Policy Case would be achieved, including energy efficiency, renewables, and CHP implementation as discussed above. More detail on the emission reductions that may be obtained through these measures is described in Section 3.3.1 above, including Figure 3-1 and Table 3-3. Historical emissions data for 2005-2007 are not yet verified, and are therefore not included in Figure 4-1.
Figure 4-1
Electricity Sector Emissions Reduction Potential
Compared to Historical Electricity Sector Emissions
As discussed above, we are committed to the policies and GHG emission reductions contained in the Reference Case and the Accelerated Policy Case. We recognize that these policies may result in slightly more or slightly less emissions reductions, depending on actual progress during the 2020 timeframe. All of the emissions reductions shown above result from assumed levels of direct or programmatic approaches and mandates and not from a cap-and-trade system. As described in Section 3.3.1 above, these emissions reduction measures, before consideration of a cap-and-trade program, would result in 2020 emissions in the electricity sector of approximately 79 MMT, about 27% below its 1990 emissions level. This projected 2020 emissions level under the Accelerated Policy Case would be approximately 38% lower than the 129 MMT estimate resulting from "business as usual" in the absence of any climate change policy in California, in which additional growth in electricity demand is met solely with natural gas-fired resources (the Natural Gas Only Case).
ARB's Draft Scoping Plan would assign approximately 40% of the economy-wide responsibility for mandatory emissions reductions to the electricity sector, even though electricity represents only 25% of the statewide emissions. Using ARB's assumptions, this requirement would result in electricity sector emissions in 2020 roughly equal to the level that E3 estimates under the Accelerated Policy Case. If electricity is included in the cap-and-trade program contemplated in the Draft Scoping Plan, and were to achieve the additional emissions reductions that ARB expects from the cap-and-trade program, the electricity sector could, in total, deliver as much as 55% of the required emission reductions in the State (if the electricity sector were to deliver the majority of the additional 35 MMT of reductions that ARB projects will need to come from the capped sectors).
We fully expect that, as the second largest contributor to California's GHG emissions after transportation, the electricity sector will bear a large share of the emission reduction responsibility under AB 32. The electricity sector is a sector in which techniques for reducing emissions are already known and generally fairly quantifiable and feasible. However, we caution that the temptation to assign as much responsibility as possible to this sector should be avoided.
We are mindful of the responsibility to ensure cost-effectiveness of AB 32 measures, as well as to keep costs to consumers at a reasonable level. As noted above, the responsibility for reducing emissions can be separated from the recovery of the cost of the emission reductions.
Electricity is a somewhat unique commodity in modern life in that it is necessary both to sustain quality of life for individuals, and for the production of other necessary goods and services. Unlike many other goods and services, there are no ready substitutes for electricity in the economy (except for natural gas or other fuels, in some instances), and low-income consumers rely on electricity in their daily lives. In the territories of some investor-owned utilities, up to one-third of the customers are low-income. The proportion of low-income customers may be even higher in particular areas of investor-owned or publicly-owned utilities' territories. Therefore, we must be concerned about overburdening the sector as a whole, and low-income electricity consumers in particular, when designing AB 32 regulations for the electricity sector.
Figure 3-2 in Section 3.3.1 above, which we duplicate for convenience as Figure 4-2 below, contains E3's estimates of the total utility costs occurring in the three resource policy scenarios it examined: the Natural Gas Only Case, the Reference Case, and the Accelerated Policy Case scenarios. As can be seen from this figure, utility costs are projected to increase from current levels (above inflation) under all scenarios, largely because of generally increasing costs of natural gas and increasing capital costs of renewable and conventional generation as well as transmission and distribution facilities. The Accelerated Policy Case has more aggressive energy efficiency, renewables, California Solar Initiative, and CHP requirements. However, total utility costs would be higher in 2020 without those more aggressive policy options, with the data underlying Figure 4-2 indicating that total utility costs would be 4% higher in the Reference Case and 9% higher in the Natural Gas Only Case. This is chiefly because of the high levels of cost-effective energy efficiency assumed to be achieved in the Accelerated Policy Case. If those high levels of energy efficiency are not achieved, utility costs would go up commensurately.
Figure 4-2
Utility Costs, Customer Costs, and Average Rates in Three Key Scenarios
Some costs associated with increased levels of energy efficiency and other demand-side resources will be borne by individual consumers purchasing equipment, rather than by utility ratepayers. E3's estimates of those private costs in 2020 are included in Figure 4-2 above. E3 did not estimate consumers' private costs in 2008.
The average rates in Figure 4-2 mask significant variations in current rates (see Table 5-1 below) and potential rate impacts that may occur for individual retail providers. Larger rate increases are anticipated for some retail providers, while others will likely see more modest increases. In addition, individual retail provider results will be heavily influenced by the allowance allocation policy under a cap-and-trade program, if implemented, as discussed further below and in Section 5 of this decision.
It is important to point out that the estimated percentage rate increases are uniformly higher than the percentage cost increases shown in Figure 4-2 due to energy efficiency. If energy efficiency is successful, utilities will need to recover their fixed costs while selling less electricity, which causes per-kWh rates to increase by larger percentages than costs.
We also note that these forecasted rate impacts are averages for all customers; we did not ask E3 to estimate the rate impacts on particular types of consumers owing to the inherent complexity and variation in tariff structures for various types of customers of each utility. The actual impact of rate increases will be felt differentially by different types of consumers; the rate increases may be more difficult for consumers with little discretionary usage. Customers with greater ability to take advantage of energy efficiency opportunities to manage their energy usage may see little or no bill increases.
Our discussion to this point has focused on the cost and average rate impacts that will result from programmatic mandates. We also are concerned about the additional costs that may be borne by the electricity sector and its consumers as part of a cap-and-trade program. Therefore, we discuss next and make recommendations regarding cap design and allowance allocation.
As discussed above, while we agree that the electricity sector should contribute to emissions reductions through the programmatic strategies described in this decision, we do not necessarily agree that electricity sector consumers should bear all of the costs of the electricity sector programs or any or all of the additional costs associated with a cap-and-trade system. The design of the cap-and-trade system, and its associated allowance allocation policy, can have a significant positive or negative impact on the costs borne by electricity consumers.
As a starting point, we assume that ARB will set an emissions cap for the covered sectors as a whole that takes into account projected emissions levels throughout the entire economy of California. In fact, we believe this is required, since AB 32 requires attainment of 1990 emissions levels for the State as a whole, and not just in capped sectors.
As ARB conducts a sector-by-sector bottom-up analysis, we urge ARB not to assume or project additional emission reductions from the electricity sector beyond the levels contemplated by E3's Accelerated Policy Case, with one exception. As discussed in Section 4.1.1.2 above, we are committed to achieving all cost-effective energy efficiency in California. However, this level could not be modeled by E3 due to unavailability of reliable cost estimates for the more expensive energy efficiency measures approaching the cost-effectiveness threshold. With achievement of the Accelerated Policy Case and this additional commitment to all cost-effective energy efficiency, the electricity sector will bear a burden of reductions exceeding its proportional contribution to 1990 emissions and potentially at very high marginal costs for some measures. While emissions in this sector have been stabilizing due to aggressive current policies, emissions in other sectors have been growing steadily. This sector has already done a great deal and has incurred significant costs to mitigate GHG emissions in California and should not be further burdened beyond the levels contemplated here.
In order to minimize the potential additional burden on electricity consumers, we recommended in D.08-03-018 and ARB has already acknowledged in its Draft Scoping Plan that as many sectors of the California economy as possible should be capped and participate in the cap-and-trade program. We also support linkage of California with a regional and/or national cap-and-trade system, in order to open up further opportunities for GHG mitigation at lower cost than may be possible within California, so long as the programs with which California links are sufficiently stringent to meet AB 32 requirements. We also make additional recommendations in Section 7 related to flexible compliance, to ensure that the electricity sector participants in the cap-and-trade program have essential flexibility to keep costs low for electricity consumers. In addition to mandatory programs, the design of the cap-and-trade system has the potential to have a large impact on consumer costs.
We recommend that any further electricity sector reductions required as part of a multi-sector cap-and-trade program should be justified based on detailed analysis of the costs of GHG mitigation in other sectors. Until that additional analysis is conducted, we recommend that the electricity sector not be required to reduce its emissions below the approximately 79 MMT CO2e estimated in E3's Accelerated Policy Case.
As noted in Section 3.4.4 above, some additional costs would be borne by the electricity sector consumers as a result of inclusion in a cap-and-trade system, since the inclusion of a carbon price would result in higher wholesale electricity market prices, whether or not additional GHG reductions are achieved in the sector.
In a cap-and-trade system where some allowances (or allowance values) are administratively allocated, ARB will need to determine the proportion of allowances (or allowance value) to allocate to the electricity sector as a whole. This decision will have a potentially large impact on electricity consumer costs and rates.
While E3 did not analyze inter-sectoral cost and equity issues, we can make some general recommendations about how ARB's allowance allocation policy should treat the electricity sector. Section 5 of this decision contains our intra-sectoral allocation recommendations.
We do not know enough about ARB's potential cap-and-trade program design or about emission reduction opportunities in other sectors to make precise recommendations regarding the specific level of allowances that should be allocated to the electricity sector. However, we can make some general recommendations regarding the allocation approach that ARB should follow absent convincing information justifying a different approach. We recommend that ARB assign allowances (or allowance value) to the electricity sector at the beginning of the cap-and-trade program in 2012 based on the sector's proportion of total historical emissions during chosen baseline year(s) in the California sectors included in the cap-and-trade program, including emissions attributed to electricity imports. 34 We recommend that, in subsequent years, allowance (or allowance value) allocations to each California sector in the cap-and-trade program be reduced proportionally, using the overall trajectory chosen by ARB to meet AB 32 goals by 2020.
As an example of this allocation recommendation, if ARB creates allowances in a specified compliance year equal to 90% of the historical emissions in the sectors in the cap-and-trade program (including emissions attributed to electricity imports) during a chosen historical baseline period, the electricity sector would receive allowances equal to 90% of its actual emissions (including those attributed to imports) in the chosen baseline year(s).
With this allocation recommendation, while the electricity sector may provide more than its proportional share of GHG emissions reductions through both mandatory programs and market-based reductions occurring due to the cap-and-trade program, it would bear a roughly proportional share of emission reduction costs under the cap-and-trade system as compared to other sectors in the cap-and-trade program. Also, this approach would recognize early actions that entities in the capped sectors have taken to reduce emissions after the baseline period.
We also recommend that the trajectory of the multi-sector cap and the required annual reductions be generally a straight-line reduction between 2012 and 2020 for all sectors in the California cap-and-trade program, including electricity. In general, we favor steady progress toward the 2020 goals, which implies equal reductions annually between 2012 and 2020. 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 reductions.
Regardless of whether ARB chooses a straight-line trajectory for the multi-sector cap, we emphasize the need to allocate the allowances proportionally among the sectors in the cap-and-trade program, based on relative emissions during an historical baseline period. Whether there are multi-year compliance periods will affect the electricity sector greatly, due to annual weather variations (as further discussed in Section 7 on flexible compliance below). If the annual cap reduction trajectory is not linear, we will need to examine carefully the impact on the electricity sector.
We note that during the first phase of the European Union Emission Trading Scheme, non-electricity sectors generally were allocated allowances to cover their expected emissions, while the allowance shortfall fell entirely on the electricity sector. For the reasons stated earlier about the impact on consumer cost in the electricity sector, we cannot support such an allocation policy in California. Because we are committing to aggressive policy mandates in the electricity sector, further reductions should not be required of the electricity sector, though we recognize that there may be some efficiencies available by generators within the 2020 period. Any further decisions about allowance allocation to the electricity sector should, at a minimum, be based on some analysis of the proportionality of the burdens being borne by each sector of the California economy. The additional reductions necessary to meet the AB 32 goal should not rest solely or even primarily on the electricity sector, given how much has already been achieved in the sector. If ARB determines that additional emission reduction measures should be mandated for the electricity sector, ARB should distribute additional allowances or allowance value to the electricity sector, so that the related costs would be shared among the sectors rather than borne by the electricity sector alone.
We continue to emphasize the need for careful monitoring of the performance of all electricity sector programs, including the cap-and-trade program, to ensure the program goals are achieved and that performance and cost information is obtained.
We have not addressed in this proceeding other emission reduction measures that may reduce overall California GHG emissions but increase emissions in the electricity sector. Chief among these is likely to be the electrification of transportation through, for example, electric vehicles and plug-in hybrids. This area will require further work as we coordinate with ARB on the development of the Low-Carbon Fuel Standard and the Scoping Plan. In order not to create a disincentive for the electrification of transportation, ARB may need to allocate extra allowances to the electricity sector to account for the increase in emissions and the increased sectoral GHG compliance obligations expected as a result of these and other potential policies. We do not know enough about the magnitude of the expected impact, but expect to work closely with ARB as these policies and technologies develop.
ARB's Draft Scoping Plan indicates a desire to phase in inclusion of the natural gas sector (residential and commercial natural gas combustion) in the cap-and-trade program during the 2012 to 2020 timeframe. This is generally consistent with our recommendation in D.08-03-018 to consider later inclusion of natural gas in the cap-and-trade system. At this time, our analysis of the potential for natural gas sector contributions to the AB 32 2020 reduction goals is limited to the potential for energy efficiency, including utility programs, building codes, and appliance standards, affecting natural gas use, and solar hot water. Thus, we do not make recommendations regarding the natural gas sector contribution to GHG reductions, except that we recommend that ARB set natural gas energy efficiency requirements in its Scoping Plan at the level of all cost-effective energy efficiency, with energy efficiency goals for investor-owned utilities set based on those adopted by the Public Utilities Commission in D.08-07-047, and as may be revised and updated by the Public Utilities Commission from time to time.
We also note that, similar to the potential for electrification of vehicles as described above, natural gas is a potential alternative fuel to gasoline for transportation. We will need to work closely with ARB to estimate the potential impact on the natural gas sector of increased use of natural gas as a transportation fuel.
26 The natural gas sector, as defined in the amended scope for this proceeding, is described in D.07-05-059 and consists mainly of natural gas combustion chiefly in the residential and commercial sectors, plus fugitive emissions from natural gas pipelines and other infrastructure.
27 ARB's Draft Scoping Plan has recognized solar hot water heating as an important measure that is also related to reaching the "zero net energy" goals of both Commissions in 2020 and 2030 for residential and commercial buildings, respectively.
28 This program includes the California Solar Initiative, the New Solar Homes Partnership, and other photovoltaic programs.
29 ARB Draft Scoping Plan, Appendices, p. C-77.
30 In 2005, the Public Utilities Commission published a report prepared by the Center for Resource Solutions assessing the cost impacts of a 33% renewable electricity target. The findings of that report and other analyses were included in the 2007 Integrated Energy Policy Report.
31 R.08-02-007 scoping memo, p. 8.
32 If tradable RECs from the California Solar Initiative are allowed in the RPS progam, care must be taken not to double-count the GHG emissions reductions. See D.07-01-018 in R.06-03-004.
33 The Draft Scoping Plan includes CHP as an emissions reduction strategy in the "energy efficiency category." In proceedings before the two Commissions, energy efficiency typically refers to demand-side strategies to save energy; CHP is inherently a supply-side fuel-efficiency measure. We note this distinction in order to avoid any confusion about the two classifications.
34 We recognize that certain deliveries of imported power might be excluded from California's cap-and-trade system if they are included in comparable cap-and-trade programs elsewhere, which might happen as a result of Western Climate Initiative implementation. If that occurs, the historical baseline for calculating the allocation of allowances to and within California's electricity sector might need to be revised to reflect the reduced scope of the California cap-and-trade system.
