3. Threshold Policy Issues
In order to determine an approach to the procurement incentive framework, the Commission must address a number of threshold issues. First among these is the question of the appropriate characteristics of a procurement incentive framework. Should the framework be based around a cap on GHG emissions? If so, what type of cap is appropriate? To whom should such a cap apply? What role should financial incentives play in procurement choices of the IOUs, to encourage investment in preferred resources in the EAP "loading order" (such as energy efficiency and renewables)?
We address these threshold questions in this section, and associated implementation issues in Section 4. In doing so, we briefly summarize the parties' positions on each issue, as presented in their pre- and post-workshop comments, concentrating on the chief points of contention. We do not attempt to summarize every nuance in individual positions. A more extensive discussion of the issues is provided in the Workshop Report.
Unless indicated otherwise, our reference to a GHG emissions cap refers to emissions associated with electric generation, and does not include emissions from non-electric generation usages of natural gas.
3.1. Role of a Greenhouse Gas (GHG) Cap in Procurement Policies
In this section, we discuss whether setting a cap on GHG emissions is an appropriate driver for a procurement incentive framework.
UCS believes that the Commission's procurement incentive framework should include a GHG emissions cap. In UCS's view, such a cap provides quantitative incentives for procurement actions to follow the EAP loading order and helps direct any investments in fossil generation to lower emitting options. UCS also believes that a GHG emissions cap provides a quantitative measure against which to judge procurement performance and apply financial incentives.
GPI believes that a GHG reduction program is needed, but that it must be designed to merge easily and effectively into the inevitable national and international systems. While it may be that the reduction of GHGs is the "objective function" of environmental policy (i.e., singular emphasis that will yield a range of desired benefits), GPI feels that further study is required. GPI suggests that the Commission continue to develop its preferred resources aggressively, to the fullest extent possible. According to GPI, the sooner the major energy companies in California begin to adjust their practices and position themselves for future compliance, the better off they will be in the long run.
NRDC believes that the Commission should simultaneously support a Legislative effort to establish a cap-and-trade regime for all emissions from the electric and natural gas sectors, while continuing to develop policies for IOU caps alone. The IOU-specific approach, according to NRDC, should be developed via a series of joint workshops with the CEC and its Climate Change Advisory Group.
TURN believes that a legislatively mandated statewide program would be preferable, but that in its absence, the Commission should still continue to work in this area to prepare for the time when a statewide program is enacted. TURN agrees with NRDC that the Commission should work with the CEC Climate Advisory Group on a joint task force.
DRA believes that the Commission should open a new proceeding to further develop the issues presented in the workshops held by the Commission in March 2005. DRA is concerned that overlaying a GHG regime on existing preferred resource programs may lead to duplication, uncertainty, and higher ratepayer costs. DRA's preferred approach to a GHG reduction framework is to accelerate the EAP initiatives.
CAC/EPUC propose that the Commission continue to develop its policies, but implement them only in the context of a broader statewide or regional policy. They are concerned that the Commission not competitively disadvantage the IOUs and/or their suppliers. CAC/EPUC argue that unforeseen consequences such as higher prices, reduced availability of generation, and system gaming could occur.
Solargenix strongly supports the imposition of a GHG emissions cap on the IOUs, on the basis of load.
Sempra believes that a GHG incentive mechanism to address the global problem of climate change should not be crafted too narrowly, and expresses particular concern over leakage and contract shuffling issues. Sempra believes that a GHG mechanism must do the following: set an accurate baseline and achievable reduction targets, treat imports, avoid double-counting with the carbon adder (adopted in D.04-12-048), support incentives for the EAP loading order, allow trading, and not inhibit the development of broader GHG frameworks.
Duke comments that a GHG incentive system should encourage the repowering of old facilities, and allow for generation not presently within the IOU portfolio to obtain contracts, repower, and improve GHG performance.
SDG&E believes that a cap would be premature, arguing that the semblance of normalcy has only very recently returned to markets. In SDG&E's view, a cap would have a destabilizing effect on procurement. SDG&E also argues that the imposition of a cap would make the utility responsible for issues that cannot be controlled directly, such as population and economic growth. In addition, SDG&E believes that cap design will take years of study. For these reasons, SDG&E recommends staying the course with EAP commitments and awaiting federal/international coordination on a comprehensive GHG framework.
SCE has similar reservations about moving forward with a GHG-based procurement incentive framework. In particular, SCE contends that a GHG cap would encourage bypass of the utility system through customer migration, cause leakage by moving generation projects outside of California's procurement footprint, and create financial incentives for laundering contracts to create an appearance of displacement of generation. SCE believes that incentive frameworks that are too broad will not be compatible with long-term procurement planning, and will unduly constrain the IOUs' choices. In SCE's view, a focus on EAP resources is the best method of promoting GHG goals. SCE comments also express concern about fairness to all California LSEs as well as the potential burden on the California economy. In sum, it is SCE's position that efforts to regulate the production of GHG are best made at a national level across all carbon-emitting sectors.
PG&E recommends coordinating efforts with the CEC, CalEPA, the California Air Resources Board and the West Coast Governor's Global Warming Initiative. In the absence of a national approach, PG&E supports regional programs that incorporate diverse industries and the broadest possible geographic area. PG&E recommends that the Commission work to coordinate the multiple state-level efforts to create the equivalent of an EAP for climate change. PG&E does not believe that a GHG cap should be adopted now; instead, existing EAP commitments should be embraced as the means to achieve GHG reductions. PG&E recommends that the Commission work with CCAR to develop a protocol for load-based accounting across the West. However, PG&E recommends that if the Commission does develop a cap program, it should be flexible enough to be superseded by state or federal programs. Finally, PG&E states that GHG caps can be considered separately from procurement incentive issues.
The question of whether to establish a GHG emissions cap is the threshold "fork in the road" policy issue in this phase of the proceeding. Many parties presented various views on this topic that ranged from extremely cautionary, recommending that the Commission wait for national or international policy consensus, to extremely enthusiastic, recommending that the Commission proceed now to establish a GHG emissions cap.
At this juncture, we are inclined to proceed proactively to establish a GHG emissions cap. There are several important reasons why we make this choice to proceed. First and foremost, since the initiation of this proceeding and the workshops this past spring on this topic, Governor Schwarzenegger has announced very aggressive GHG emissions targets for the state of California to reach. In doing so, he stated that California will be "the leader in the fight against global warming" and furthermore, that "the time for action is now."10 Our GHG Policy Statement echoes this imperative. In particular, it recognizes that current approaches for internalizing "the significant and under-recognized cost of GHG emissions" through a GHG adder must be augmented in order to meet EAP II and the Governor's GHG goals.11
The electric sector is one of the most important categories of GHG emissions to be addressed in the state, representing approximately 20% of California's climate change emissions.12 This Commission has a great deal of authority over the largest component of the electric sector in the state, and we wish to move forward in a leadership role to help support the GHG reduction goals of Governor Schwarzenegger. Establishing a GHG cap is consistent with the Governor's objectives for climate change policy, as well as our own GHG Policy Statement. By resolving the "fork in the road" policy issue today, we can now focus our efforts on addressing the myriad of implementation questions, including the appropriate level of GHG reduction requirements over time.
We agree with those parties that suggest we coordinate with other agencies in California in this process. We also agree that any policies we adopt should be compatible with any eventual regional, national, or international climate change policies that may develop in the future. In addition, we agree that we must start by addressing reporting and baseline issues associated with GHG emissions and incorporating GHG planning into procurement activities. We intend to do all of these things, with our eyes firmly on the goal of implementing a cap on GHG emissions in California for IOUs and other LSEs as soon as possible.
3.2. Type of Cap on GHG Emissions
The workshops, workshop report, and parties' comments discussed several types of GHG emissions caps available. The two major options are a load-based cap or a generation-based (or sector-based) cap. Under a load-based cap, the LSEs would be subject to a GHG emissions cap for all resources procured to serve their load, no matter from what source, including imports. Under a generator-based cap, each generator would be subject to a GHG emissions cap.
Most parties commented on the type of cap that is preferable in the context of concerns about "leakage" and "contract shuffling." Leakage refers to the inability of a California-based cap to address the GHG emissions of out-of-state generation that is imported into California to serve load. Contract shuffling refers to the ability of suppliers who have a large portfolio of resources to allocate their contracts to California in such a way as to show a reduction in GHG emissions without actually lowering their GHG emissions, simply by assigning lower GHG-intensive resources to California delivery.
NRDC argues that leakage is best addressed through the establishment of a load-based GHG emissions cap. TURN agrees. Sempra also prefers a load-based cap, if one must be established at all.
Solargenix states that all generators should be required to register their emissions, but does not offer a direct opinion on whether a generator-based or load-based cap would be preferable.
SCE and SDG&E oppose establishing a load-based cap. SCE likens it to a "downstream" control regime, and cites a Congressional Budget Office study arguing that downstream trading systems are cost-prohibitive. In its reply comments, NRDC refutes this conclusion, arguing that the study's reference to "downstream" approaches is actually more similar to a generator-based cap than a load-based cap.
SDG&E is more concerned that whatever cap is established in California be compatible with other future cap-and-trade programs regionally, nationally, or internationally. SDG&E argues that a load-based procurement cap will be incompatible with other cap-and-trade programs in the rest of the world. NRDC replies that a load-based system will create allowances representing a unit of GHG emissions, and will therefore be compatible with other cap-and-trade programs that may be established.
Despite the objections of the IOUs, we agree with the majority of parties commenting that a load-based GHG emissions cap is preferable to a generator-based cap. For one thing, a load-based cap is the type of cap over which the CPUC has obvious authority with regard to procurement practices. Our authority to impose a GHG cap on exempt wholesale generators under the jurisdiction of the Federal Energy Regulatory Commission is more questionable.
Furthermore, we agree with NRDC and others that a load-based cap is far preferable in minimizing the potential for leakage across California's borders due to the sizeable reliance of California on imported electricity resources, at least at this time. With respect to concerns over contract shuffling, we note that any initiative that California takes to lead the way in GHG emission reductions by establishing reduction targets or caps will be susceptible to that potential until other states follow our lead. However, as discussed during workshops, there are approaches we may be able to take (such as "MWh tagging") during implementation that will enable us to track and quantify any contract shuffling that may occur.
Finally, we make clear that we wish to create a load-based GHG emissions cap that is compatible with any other GHG cap-and-trade regime that may be developed in the future, either in the Western Region, nationally, or internationally. Thus, we will proceed to develop a load-based cap where GHG emissions allowances are fungible. In order to do that, we must ensure that "a ton is a ton" of carbon dioxide emissions under our load-based cap. Thus, our emissions allowances will be in the form of "tons of carbon-dioxide equivalent."
In comments on the draft decision, GPI points out that other GHGs in addition to CO2 have significant impacts on climate change, and requests that we clarify our intent with regard to what GHGs will be included under the cap. Our intent is to ultimately include all six of the major GHGs under the load-based cap, as feasible over time.13 We note that CCAR currently requires that all six must be included in the fourth year of reporting. The regulated IOUs are preparing for that fourth-year report at this time. During the implementation phase, we will consider the implementation details and timeline for including each of these major GHGs under a load-based cap.
3.3. Applicability of Cap
During the workshop process, some parties raised the issue of the CPUC's legal authority to impose a GHG emissions cap on IOUs and on non-IOU LSEs such as community choice aggregators (CCAs) and electric service providers (ESPs). In addition to relevant policy and implementation issues, the assigned ALJ directed interested parties to comment on what, if any, legal issues the Commission would need to address if it adopted a GHG cap for procurement.
SCE and SDG&E were the only two parties that filed written comments in response to the ALJ's request on whether and how a GHG cap may be applied legally to IOUs or non-IOUs by the CPUC. Generally, both utilities argue that the CPUC should not impose a GHG limit on IOUs because it would be unfair or discriminatory to regulate only IOU emissions and not those of other providers in the marketplace. In addition, SDG&E postulates that Interstate Commerce Clause of the U.S. Constitution might prevent the CPUC from regulating the GHG emissions of out-of-state generators selling into the California market.
By stating our policy preference for a load-based GHG emissions cap in this decision, we are confining our regulatory reach to our jurisdiction over LSEs in California. Though some parties question the wisdom of our establishing GHG emissions restrictions on IOUs, no party argued until comments on the draft decision that we do not have the authority to do so. We believe that regulating the GHG emissions of IOUs falls squarely within our authority over their procurement activities pursuant to Pub. Util. Code § 701. This statute is permissive, not restrictive: "the commission's powers are not limited to those expressly conferred on it: the Legislature further authorized the commission to `do all things, whether specifically designated in [the Public Utilities Act] or in addition thereto, which are necessary and convenient' in the exercise of its jurisdiction over public utilities."14 The Supreme Court has described the Commission as "a state agency of constitutional origin with far-reaching duties, functions and powers" whose "power to fix rates [and] establish rules" has been "liberally construed."15 No party cites any statute directly barring the CPUC from issuing these regulations on public utilities, nor justifies an argument that pollution and emissions from utility generation or purchased power are not "cognate or germane to the regulation of public utilities," the primary limiting factor on Commission jurisdiction.16
In comments on the draft decision, SCE argues that the Commission cited no direct statutory authority to regulate GHGs as they relate to utility procurement, and thus that the Commission must be asserting some implied authority. As noted above, Section 701 provides such broad and direct authority. SCE suggests by its comments that such regulations may not be "cognate or germane to the regulation of public utilities," but does not explain why the environmental effects of utility purchasing activities are not proper regulatory subjects for this Commission. For example, Section 701.1 directly states that a goal of utility resource planning is "to improve the environment." The Commission is empowered to take into account environmental factors, including air emissions, as part of our jurisdiction over utility resource planning. SCE's reliance on Southern California Gas Co. v. CPUC, 24 Cal.3d 653 (1979), cited by SCE on page 12 of its comments, is misplaced, as in that situation legislation directly stated the Commission should allow utilities the option of offering a financing program for customers, but the Commission absolutely required the utilities to offer such a program.
EPUC also argues that the Commission was not granted authority to restrict GHG emissions, and claims that Section 701.1 "specifically prohibits remedies such as a carbon cap" and "does not . . . allow the Commission to impose caps on emissions from generating resources in the utility portfolio." EPUC's argument rests on a strict interpretation of the statute: "[Section] 701.1 addresses very narrowly and specifically the Commission's authority with respect to air quality impacts from utility procurement."17 EPUC asserts the draft decision violates Section 701.1(g), which states that "[n]o provision of this section shall be construed as requiring an electric utility to alter the dispatch of its power plants for environmental purposes." EPUC cites no other part of the statute as specifically prohibiting the Commission from a remedy such as a carbon cap, and there is no such language in the statute. We further disagree that as a result of this decision, the Commission would be acting pursuant to Section 701.1 to require an electric utility to alter the dispatch of its power plants for environmental purposes. Section 701.1 does not bar the Commission from setting a load-based emissions cap.
We do not believe that this regulation violates any Interstate Commerce Clause principles, as SDG&E, SCE, and EPUC suggest. By setting a load-based emissions cap on the IOU's procurement portfolio, we are not treating out-of-state resources any differently than we are treating in-state resources that are used to serve an IOU's load.18 California and non-California generators are all subject to the cap and must adjust their behavior accordingly. The cases cited by commentors involve state regulations that facially discriminated between in-state and out-of-state commercial interests.19 SCE's arguments that the proposed regulations will result in improper extraterritorial effects are misleading and disingenuous, as the proposed regulations do not directly control the prices for electricity paid for in other states, nor regulate transactions wholly taking place outside of California.20 Therefore, there should be no conflict with respect to the Interstate Commerce Clause.
EPUC argues that the regulations are invalid because they violate a purported national, unified regulatory policy for GHG emissions.21 SCE argues that such regulations are contrary to a purported "federal foreign policy" that has rejected limits on GHG restrictions. However, neither party cites any federal statute or national, uniform scheme of regulation that the proposed regulations would violate, or any court decisions that have precluded any states from regulating GHGs. General assertions of a legislative or executive intent are not sufficient to preclude state legislation without specific legislation or regulations expressing such a clear intent.22 Indeed, states such as California can exceed minimum national uniform air pollution requirements, directly contradicting EPUC's claim that there is such a national, uniform scheme for air pollution. SCE concedes that the issue of California "statewide GHG policy" is currently being litigated in the United States District Court,23 contradicting any notion that there is already a settled federal policy that pre-empts state regulation of GHGs. Moreover, as NRDC's reply comments reveal, there are contrary interpretations of current Senate policy towards GHG regulations. We cannot agree that California is precluded from regulating GHGs in the absence of any definitive legislation, federal regulations, or court rulings pre-empting the state from doing so.
This leaves the issue of whether the CPUC has authority to establish a load-based GHG emissions cap on non-IOU LSEs such as ESPs and CCAs. Assembly Bill 380, signed into law by Governor Schwarzenegger on September 5, 2005, grants the Commission the following authority in new Pub. Util. Code § 380(e):
"The commission shall implement and enforce the resource adequacy requirements established in accordance with this section in a nondiscriminatory manner. Each load-serving entity shall be subject to the same requirements for resource adequacy and the renewables portfolio standard program that are applicable to electrical corporations pursuant to this section, or otherwise required by law, or by order or decision of the commission. The commission shall exercise its enforcement powers to ensure compliance by all load-serving entities."
There are two key portions of this code section. First, the Commission is required to impose resource adequacy requirements in a "non-discriminatory manner" and second, the Commission is given explicit authority over both the resource adequacy requirements and the renewables portfolio standard (RPS) program performance for all LSEs. Moreover, as discussed in D.05-11-025, other statutory provisions reinforce the Commission's authority over CCAs and ESPs for procurement-related activities, in particular, for the RPS program. We believe that limiting GHG emissions from LSEs (including CCAs and ESPs) as part of our regulatory framework for procurement is a logical extension of this authority, in order to ensure that all LSEs are subject to the same requirements for resource adequacy and the RPS, as required by § 380(e). The Commission also has the authority to exercise limited jurisdiction over non-utilities in furtherance of their regulation of public utilities under Pub. Util. Code § 701. (See PG&E Corp. v. CPUC, 118 Cal. App. 4th (2001) 1195-1201.) Consistent with the approach taken in D.05-11-025, during the implementation phase we will determine which terms and conditions of GHG reduction requirements and associated caps should be imposed on ESPs, CCAs, and IOUs in a similar fashion, and those where differences may be appropriate.
Alliance for Retail Energy Markets (AREM), in reply comments on the draft decision, claims that PG&E Corp. v. CPUC does not support the draft decision's regulation of non-IOU LSEs, because "Section 701 can expand the Commission's powers in a very limited way when doing so is cognate and germane to the regulation of public utilities." AREM also asserts that such regulation would contravene Section 394(f), which provides that "[n]othing in this part authorizes the commission to regulate the rates and terms and conditions of service offered by electric service providers."24 As we have stated above, regulating the GHG emissions of entities providing service to utility customers is cognate and germane to the regulation of public utilities. Section 380 provides direct authority for this Commission to regulate all LSEs for procurement-related activities. Moreover, it would provide a competitive advantage to non-IOU generation over IOU generation if only IOU generation were subject to GHG emission limits. Such limited measures do not amount to general regulation of the rates or terms of services provided by ESPs and are related to the Commission's regulatory authority over public utilities.
As a general policy, we believe it is imperative that GHG reduction goals and responsibilities be shared as broadly as possible. Therefore, in addition to exercising our authority to apply a load-based GHG cap on IOUs, ESPs, and CCAs, we will also work with the Governor's Climate Action Team to ensure that municipal utilities are also subject to a GHG emissions reduction regime that will assist California in meeting the aggressive GHG reduction goals articulated in Executive Order S-3-05.
3.4. Role of Financial Incentives
In this section, we discuss both the advisability of offering shareholder incentives for procurement performance, as well as whether those incentives should be developed on a portfolio-wide or category-specific basis. By portfolio-wide incentives, we refer to incentives that could be offered to utilities for optimizing the costs of their entire portfolio, after factoring in the risks of various resources included in that portfolio.
By category-specific incentives, we refer to financial rewards to IOU shareholders for superior achievement in procuring particular GHG-friendly resources, such as energy efficiency and renewable generation. Each category-specific incentive mechanism would establish a benchmark specific to that category, such as net resource savings from energy efficiency investments or savings below the market price referent for RPS programs.
A number of parties commented during and after workshops on the advisability of including financial rewards to shareholders for procurement performance.
UCS believes that incentives can help align the interests of ratepayers and shareholders, but are not necessary for meeting previously-established procurement targets. In UCS's view, category-specific incentives will motivate utilities to aggressively and effectively acquire each of the resources in a cost-effective manner. In particular, UCS believes that financial incentives are appropriate for superior performance in energy efficiency. However, UCS argues that such incentives should not be provided for RPS resources at this time, given the design parameters of existing renewable energy programs and the lack of a suitable proposal by parties. UCS would, however, support incentives for long-term resource acquisition if the practices of IOUs could be shown to indicate a shift away from GHG-intensive resources.
NRDC goes further, stating that financial incentives are necessary to align shareholder and ratepayer interests. NRDC believes that a portfolio-wide incentive approach is worth pursuing, but does not make a specific proposal. Instead, NRDC recommends that the CPUC proceed by establishing performance-based incentives for energy efficiency, followed by renewable energy. However, NRDC does not currently support an incentive structure for demand response programs because methods for determining the cost effectiveness of these resources are still under development.
In TURN's view, the Commission should focus on GHG reductions alone in this proceeding, and not distract attention by attempting to create incentives in other areas. TURN also argues that creating incentives for energy efficiency, renewables, and demand response as a means of reducing carbon emissions is premature until a GHG program is in place. TURN does, however, recommend that financial incentives be discussed in category-specific proceedings.
TURN also contends that IOU incentives to increase sales are insurmountable. Therefore, in TURN's view, it is not possible to align ratepayer and shareholder interests in an incentive mechanism for energy efficiency. Instead, TURN recommends making supply-side investments less attractive. Finally, TURN argues that since renewable investments are legislatively mandated, they should not be supported by incentives. In TURN's opinion, providing any financial incentives for such investments would be unwarranted, unnecessary, and detrimental to customer interests.
PG&E responds to TURN's position concerning financial incentives by arguing that TURN fails to understand the relationship between the utility's cost of capital and utility investment decisions, and also fails to recognize that the revenue requirement that supports their capital structure has been de-linked from annual sales for some time now. Overall, PG&E supports a procurement incentive framework that focuses on category-specific financial incentives for energy efficiency investments.
DRA's philosophy is that an IOU's reward should increase only if its risk is also increasing commensurately. Thus, DRA argues that incentives are warranted only if penalties are also in play. According to DRA, an incentive plan compliant with Assembly Bill 57 must do the following: (1) set penalties and rewards for each type of covered procurement activity, (2) establish benchmarks to judge gains and losses, (3) minimize the potential for gaming, (4) prevent the utility from influencing its own benchmark, (5) avoid significantly affecting the utility's credit rating in a negative manner, (6) establish a dead band separating penalties and rewards, (7) cap total penalties and rewards, (8) be formally reviewed in a mid-term review process, (9) establish reporting and verification procedures, and (10) establish a complaint resolution process. DRA further offers that since it is likely that any balanced incentive plan could negatively affect an IOU's credit rating, such a plan should only be developed for SDG&E at this time.
Solargenix supports financial rewards for performance as a necessary step in aligning ratepayer and shareholder interests. Further, Solargenix feels that category-specific approaches are preferable, with an emphasis on renewable energy development. According to Solargenix, this would provide the greatest amount of benefits to the ratepayer in creating generation assets. Solargenix also recommends that incentives be evaluated to encourage contract renegotiation.
SCE takes the position that category-specific incentives may be appropriate, and that they should be pursued in individual resource-related proceedings.
SDG&E believes that shareholder incentives have been found to enhance efficiency and promote the alignment of interests between shareholders and ratepayers. In particular, SDG&E requests a stand-alone assessment of their incentive framework proposal introduced in this proceeding. In SDG&E's view, financial incentives are not linked to a GHG cap, and therefore should be employed regardless of any cap policy.
As a general matter, we agree with a number of parties who pointed out that shareholder incentives can help align ratepayer and shareholder interests. We note that proposals for a portfolio-wide shareholder incentive design did not emerge from the workshop process or in post-workshop comments. While workshop participants appreciated the simplicity of a portfolio-wide financial incentive framework, there was little if any agreement on whether a single portfolio-wide incentive approach could work for all IOUs. We share the concerns of many participants that, given the multi-attribute nature of the various resources in the portfolio, it is doubtful that a single cost-optimization metric applied to the entire portfolio would yield procurement results consistent with the EAP loading order of preferred resources and other Commission procurement policies. Even if such an approach existed in theory, it appears highly uncertain that a portfolio-wide approach could be put into practice in a reasonable timeframe.
However, the record in this proceeding persuades us that financial incentives for preferred resources are worthwhile to pursue in conjunction with a GHG cap. Doing so is entirely consistent with the policies articulated in prior Commission decisions,25 as well as with the action items outlined in the EAP (I and II). In particular, those policies articulate the need to bring energy efficiency and demand-side resource investments in line with traditional supply-side resources when it comes to the opportunities to earn returns on those investments. TURN's categorical rejection of financial incentives ignores these policies.26
As noted by SDG&E and others, moving forward with category-specific financial incentives is not contingent upon putting a GHG emissions cap in place. Therefore, we intend to move ahead with both elements of our procurement incentive framework in careful coordination, in order to address potential interactions. (See Section 3.5 below.) As several parties note, financial incentive mechanisms should include both "risk and reward," that is, provide IOUs with an opportunity to earn financial rewards balanced by the risk of financial penalties for poor performance. As we have articulated in prior decisions, we believe financial awards should be granted for performance that exceeds performance thresholds that are tied to our savings goals or, in the case of RPS resources, to Legislative mandates.27
With this guidance in mind, we will proceed to evaluate shareholder risk/reward incentive mechanisms in resource-specific proceedings. We will begin with energy efficiency incentives, which are already planned to be considered in R.01-08-028 or a successor proceeding to it in 2006.28 We also intend to evaluate the possibility of shareholder incentives for RPS procurement in the future. However, given the plethora of issues under consideration related to RPS implementation in R.04-04-026, we do not commit to a timeframe for considering shareholder incentives for renewable resources at this time. We simply add this issue to the list to be considered in R.04-04-026 or its successor proceeding at a point to be determined by the Assigned Commissioner or ALJ to those proceedings, in the future.
As discussed in D.05-11-009, we are undertaking additional activities in the area of demand response "in order to ensure that our programs provide full value to California ratepayers," including the development of a cost-effectiveness methodology and measurement and verification protocols.29 Therefore, we agree with NRDC and other workshop participants that it is premature to explore financial incentives for demand response programs in the near future, although we may revisit this issue at a later date.
3.5. Interaction of GHG Cap and Financial Incentives
In the revised proposal issued for the March 2005 workshops, and discussed in the Workshop Report, staff suggested that a mechanism could be established for the CPUC to certify GHG emissions allowances for sale outside of California. The CPUC would certify such allowances for superior performance in GHG reductions, as defined by the CPUC. After certification, LSEs could sell the allowances for the benefit of their shareholders as an incentive to further reduce GHG emissions.
Only a few parties commented on this proposal in their written comments on the workshop report. UCS feels that such a proposal may be appropriate, but should be further developed after the Commission has established its baseline methodology and the downward path of the cap over time. SDG&E believes that incentives should be set for individual categories of procurement, in the appropriate individual dockets, completely separate from GHG cap questions. SDG&E also notes that energy efficiency financial incentive mechanisms under consideration include a GHG component through the avoided cost valuation of resource benefits.
NRDC generally endorses the concept of GHG allowance sales under the certification process proposed by staff, but raises a number of issues. First, they suggest that the sale of allowances should be limited in any given year, in order to encourage banking of allowances to smooth out yearly fluctuations. Also, NRDC is concerned that if LSEs receive both category-specific and GHG-targeted incentives, it may be difficult to determine what actions contributed to the overall success of the GHG reduction initiative. Finally, NRDC believes that potential shareholder rewards under the GHG-targeted incentive mechanism should also be paired with potential shareholder penalties.
We note that the staff proposal for allowance sale incentives was developed in the context of an "in California only" framework for trading/certifying offsets. (See Section 4.3 below.) As discussed in this decision, we are deferring our consideration of compliance options (including allowance trading and offsets) until the implementation phase. Therefore, the manner in which the staff-proposed allowance sales incentive mechanism would interact with the cap-and-trade framework that emerges from that phase needs to be further explored. At this juncture, we state a preliminary preference for pursuing the establishment of certified GHG emission allowances that the IOUs would be authorized to sell to the benefit of their shareholders. However, we agree with NRDC that these incentives should also be balanced with potential penalties. We agree with TURN's observations that, to the extent that ratepayer-funded projects are creating such allowances, we should not preclude from consideration the concept of "shared-savings," whereby both ratepayers and shareholders benefit from the sale of them.
We will further pursue the concept of allowance sale incentives in the implementation phase of this inquiry. We will also ensure that the design of resource-specific incentives works in tandem with this concept, in order to eliminate any double-counting of financial rewards or penalties.
As suggested in the Workshop Report, if the IOU earns a financial reward for exceeding the Commission's energy efficiency savings targets and can also sell the extra GHG allowances associated with that achievement, the calculation of the energy efficiency reward may need to be based on a calculation of net resource benefits that excludes the avoided cost of GHG emissions. Similarly, any direct financial incentives for renewable procurement, in conjunction with an allowance sale incentive, should avoid double payment for the same GHG benefit. There may be other factors to consider in dovetailing these two incentive approaches, so that double-counting and other compatibility problems are avoided.30
10 Governor's Remarks at World Environment Day Conference, June 1, 2005.
11 GHG Policy Statement, p. 1.
12 California Environmental Protection Agency-Climate Action Team Report to the Governor and Legislature, Draft dated December 8, 2006, p. 8, Figure 2-3. That figure shows the sources of GHG emissions (in terms of CO2 equivalence) as follows: Transportation at 41.2%; Industrial at 22.8%, Electric Power (from both in-state and out-of-state sources) at 19.6%, Ag and Forestry at 8.0% and all other sources at 8.4%.
13 These are: carbon dioxide (CO2), methane (CH4), nitrous oxide (N20), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6).
14 SDG&E v. Superior Ct., (1996) 13 Cal.4th 893, 915, citing Section 701, (italics in decision).
15 Southern California Edison Co. v. Peevey, (2003) 31 Cal.4th 781, 792 (citations omitted).
16 PG&E Corp. v. CPUC, (2001) 118 Cal. App. 4th 1174, 1201.
17 EPUC Comments, p. 3.
18 See Harvey and Harvey v. Delaware Solid Waste Authority, 600 F.Supp. 1369, 1380-81 (D. Del. 1985) (in reviewing an environmental statute "which does not appear to materially favor in-state economic interests . . . the role of a reviewing court is quite limited.")
19 See, e.g., Hunt v. Washington Apple Advertising Comm'n, (1977) 432 U.S. 333 at 351-52 (contrasting lack of any economic impact on in-state apple growers with increased costs on out-of-state growers), EPUC Comments, p. 6; H.P. Hood & Sons, Inc. v. DuMond, (1948) 333 U.S. 525 at 530-531 (noting that the challenged "restrictions [were] imposed for the avowed purpose and with the practical effect of curtailing the volume of interstate commerce to aid local economic interests"), SCE Comments, p. 12.
20 Healy v. Beer Inst., (1989) 491 U.S. 324, 334, 336 (determining that a regulation that would regulate price to be paid in other states and "directly controls commerce occurring wholly outside the boundaries of a State" is contrary to Commerce Clause), SCE Comments, p. 14.
21 EPUC Comments, p. 8 ("interstate commerce must not be subject to varying local regulation where uniform regulation across states is necessary and desirable").
22 See Guschke v. Oklahoma City, 763 F.2d 379, 384 (10th Cir. 1985).
23 Central Valley Chrysler-Jeep, Inc. v. Witherspoon, CIV-F-04-6663-REC-LJO (U.S. District Court, Eastern District of California), SCE Comments, p. 15.
24 Reply Comments of Alliance for Retail Energy Markets Regarding the Opinion on Procurement Incentive Framework, February 7, 2006, p. 4.
25 See, for example, D.05-09-043, mimeo., pp. 129, 132, 165-166.
26 We have also reviewed TURN's and DRA's comments on the draft decision that reargue this issue, and we continue to find their rearguments opposing the development of financial incentive mechanisms to be without merit.
27 Id. See also, D.05-04-051, mimeo., p. 56.
28 D.05-09-043, mimeo., pp. 165-166.
29 D.05-11-009 in R.02-06-001, p. 1.
30 See Workshop Report, p. 20, footnote 8.
