4. Policy Issues
4.1. UOG233
Restructuring resulted in the divestiture of most of the IOUs' conventional (fossil fuel) generation. The IOUs retained ownership of their nuclear and hydroelectric assets, which represent approximately half of the three IOUs' current capacity requirements. In the past several years, a number of conventional generation plants have been acquired by the three IOUs as a result of the August 16, 2007 ACR, various unique opportunities, and RFO selections (i.e., PSAs, EPCs, and PPAs that convert to UOG at the end of the PPA term - there have been no utility-build offers in IOUs' solicitations to date).
Issues associated with this increase in conventional UOG are generally related to one of these four questions:
· Will UOG stifle the Commission's goal of transitioning to a viable competitive market structure, or should it continue to be permitted during the transition?
· Is it possible to fairly compare UOG and merchant developer bids in RFO bid evaluations?
· If UOG continues to be permitted during this transition period, under what circumstances is it appropriate?
· Should the 50/50 savings sharing mechanism developed for UOG in D.04-12-048 be replaced?
Each of these questions is addressed in this section.
There are a wide variety of opinions among IOUs and intervenors regarding whether new UOG is appropriate for the three IOUs. The IOUs recommend the continued use of UOG as one of the procurement tools they can utilize to provide the best value to ratepayers. The ratepayer advocates generally concur with this position, suggesting that certain circumstances for or quantities of UOG will provide a good balance for developer built and owned generation. Developers are generally against UOG out of concern for either (1) the inability to fairly compare utility and developer RFO bids or (2) the incompatibility of ratepayer-backed UOG with the desired competitive market end state.
As noted above, the IOUs are all in favor of preserving new UOG as one of the procurement tools they can utilize to provide value to ratepayers.
Testimony from the developer community, which includes individual developers as well as advocacy groups like CMA and IEP, was mixed on whether or not UOG should be permitted to continue.
CMA takes the position that developers will not commit substantial capital to new merchant generation until it is clear that utilities will no longer be in the business of funding new generation through ratebase investments (or even long term PPAs) with regulatory guarantees. As CMA states in its initial testimony:
Merchant investors are willing to bear the risk that their investment can be "devalued" through the actions of other market competitors. They are not, however, willing to take the risk that their investment could be "devalued" by the actions of a utility with preferential access to regulatory guarantees. Although the common refrain is "no one will build without long term contracts," the more accurate statement would be "no one will build a new plant without a long-term contract while the state still has a policy of having utilities sign such contracts." So long as the current hybrid model is perceived to be the permanent policy of the state, there is likely to be little or no true merchant entry. The use of long term contracts backed by regulatory guarantees creates a self-fulfilling prophecy where "no one will build without one."' [CMA, Schnitzer, p. 9.]
Thus, CMA argues that all ratepayer backed investment, including but not limited to UOG, will prevent the development of a competitive energy market made up of direct private investment in generation resources.
CAC/EPUC do not object to new UOG provided that the utility projects win a fair and unbiased solicitation.
IEP notes that a long-term procurement process that favors IOUs will discourage potential wholesale suppliers from identifying and developing opportunities to serve the California market and investing in the costly process of development and bid preparation; potential suppliers will be less willing to participate in a game where the deck has been stacked against them. IEP states that the preservation of the benefits of competition (through effective regulation and oversight) requires regulation that embodies the relevant principles of competitive procurement in rules to which the IOU is bound and provides oversight to ensure that the regulation is effective.
CARE appears to advocate for UOG until the risks associated with PPAs are better understood. CUE argues that the Commission should continue to encourage the IOUs to examine ownership options and that IOUs should enter into them when appropriate. CUE suggests that there will always be a range of generation costs, risks, and benefits not just between utility-owned and contracted-for generation, but among different utility-owned generation options and among different contracted-for generation options. Thus, it is appropriate to both keep open the option for utility-owned generation and also keep flexibility about the rate treatment to be applied to different generation resources.
Aglet recommends that the IOU Plans be modified so that a target of 50% UOG is established for all new contracts with terms of 10 years or greater and that the target should apply to both renewable and non-renewable resources. TURN urges that UOG should be permitted, because "cost-based generation needs to be available to discipline the market, every bit as much as the market needs to be available to discipline the utilities" (TURN's Opening Brief, p. 28). TURN identifies conditions under which UOG should be permitted, and these conditions are discussed later in subsection 3.
CMA's position that continued reliance on UOG (and ratepayer-backed PPAs) is incompatible with the development of a competitive market model that stimulates private investment is consistent with basic economic theory. The Commission is taking measured, cautious steps in the direction of this end-state, and a number of programs and security measures must be developed and tested before California relies on competitive markets to provide this critical resource to our state. D.06-07-029 stated that we were in a transitional period, and this remains the case. Anticipated rulings on forward RA requirements (and the market structures for acquiring these resources) in Phase 2 of the RA proceeding and the development of a transparent PRM methodology in the PRM rulemaking are key steps in this process. To a great extent, they represent the "horse" to this proceeding's "cart," and we must be mindful that our actions do not put the cart in front of - and, more importantly, in the way of -- the horse.
We recognize the need for policy consistency with the forward RA structure and revised PRM methodology, but until they are developed and implemented this proceeding will continue to be relied upon to (among other things) ensure that sufficient resources are available to ensure system reliability throughout the state. We are prepared to curtail or prohibit new, fossil fuel UOG, and even ratepayer-backed PPAs, if we are convinced that other mechanisms are in place to perform this function. Until we are further down this path, though, we see no reason to dismiss out-of-hand any particular method for acquiring these resources.
We do not prohibit UOG in this decision; however, we weigh heavily in the remainder of this section the concerns related to UOG expressed by the IPP community as we consider whether and how UOG and IPP bids can be compared in a competitive solicitation and the appropriate role of UOG in IOU procurement. However, we do weigh heavily in favor of a competitive market first approach as we discuss further.
D.04-12-048 stated that "The IOUs will employ the LCBF methodology when evaluating PPAs and utility-owned bids in an all-source open RFO, taking into account the qualitative and quantitative attributes associated with each bid," and the qualitative and quantitative attributes were defined as "performance risk, credit risk, price diversity (10 vs. 20-year price terms), and operational flexibility etc." (D.04-12-048, FOF #86.) Finding of Fact #86 in D.04-12-048 also indicated that "It is expected that the Commission will revisit the LCBF methodology, integrating `lessons learned' from future all-source open RFOs."
Attachment A of the September 25, 2006 Scoping Memo noted that, "(n)umerous parties have commented that the procurement practices of the IOUs to date have not promoted all-source solicitations and have not insured an even playing field for utility and non-utility electric resources to compete. See, for example, the Pre-workshop Proposal of the Independent Energy Producers Association, March 7, 2006, filed in R.06-02-013. D.04-12-048 called for open, transparent, competitive procurements. Many non-utility competitors urge the Commission to re-visit the procurement policies, and issue directives that will ensure more open competition."
There have been no utility-build bids proposed in any of the long-term RFOs since D.04-12-048 was adopted, although there has been an EPC (PG&E's Humboldt Project), a PSA (PG&E's Colusa Project), and a number of UOG acquisitions resulting from unique opportunities. The purpose of this subsection is to evaluate lessons learned from these experiences and incorporate them into the process.
There is general agreement among parties that comparing UOG to IPP bids presents many challenges. Parties who do feel that it is possible to compare UOG and IPP bids have provided precious little detail regarding how, specifically, to do so.
The IOUs take two very different positions on comparing UOG and IPP bids in the RFO process. PG&E and SDG&E both argue that UOG and IPP bids can be compared within a competitive RFO, though neither party provided any substantial description in their LTPPs regarding how the different risk and return regimes faced by the two entities would be reconciled to compare their bids fairly. SCE, on the other hand, does not believe that IOU and IPP bids can be compared in a meaningful, quantitative manner. SCE instead takes the position that generally it will offer bids in instances in which the market does not provide the product it seeks. If circumstances arise in which SCE does perceive the need to propose a utility product for which it has received market bids, SCE will provide a separate treatment of the UOG version and articulate, qualitatively, its rationale for recommending its project over the market-derived product.
CAC/EPUC do not object to new UOG per se, but recommend that UOG projects only be approved after they have been subject to an appropriately structured competitive solicitation process which allows for fair and unbiased evaluation of third-party owned projects. To do otherwise "invites mischief by the utilities by providing loopholes in the process that may seriously denigrate the integrity of the procurement process."
CMA focuses its analysis on ratepayer-backed versus privately funded generation, not on issues associated with comparing UOG and merchant PPA bids. NRG recommends that utilities be required to submit firm bids and their shareholders be held liable for overruns.
NRG also finds that as long as the IOUs are in the RFO "driver's seat" to control the timing of the RFO and the bidding process, the perceived and real likelihood of distorted outcomes remains high. NRG finds it important to recognize that even the perception of bias can be sufficient to dampen participation from other potential non-utility investors and developers are less likely to get support from capital markets if there is a perception that merchant bids will be undermined by utility built or affiliate projects. NRG concludes that the Commission or another independent agency should manage the procurement process to eliminate the potential for conflicts of interest and ensure impartiality, noting that a process of this sort has been adopted in Connecticut with considerable success.
NRG notes that, "Another benefit of state administered procurement is that there is greater likelihood of consistency among utility contract terms and conditions and credit and collateral (C&C) policies. The current contracts and C&C policies of the utilities have significant differences that are not justified in terms of the unique characteristics of each utility or service territory. These differences in contract terms add costs and raise the bar for non-utility entities to participate."
IEP makes a series of recommendations to promote fair solicitation processes. IEP argues that no potential participant in a competitive RFO, including a utility's project development group, should have preferential access to information. Therefore, IEP believes the Commission should prohibit communications of competitively sensitive information to the project development group from other utility departments.234
TURN takes the position that there can be no perfect, apples-to-apples comparison of UOG bids in their various forms and PPA bids. TURN recommends that we not let the perfect be the enemy of the good, though, and that head-to-head comparisons based on quantitative (NPV) and qualitative differences among the offers, especially with respect to the residual risks that will be borne by ratepayers. TURN notes that sometimes such factors will result in the selection of a project that is not strictly the least cost on a numeric basis, because of the ratepayer risks or other factors that the particular project encompasses.
TURN provides an additional refinement to the process, based on the Colusa PSA and PPA bid comparison that resulted in the selection of the PSA in the most recent PG&E Long-Term RFO. When a UOG and non-UOG bid are relatively close in prices, there should be a preference for the non-UOG bid.
TURN also supports IEP's proposals to ban the utility from having preferential access to information when submitting a bid for a UOG in a competitive solicitation. TURN supports functionally separating the individuals performing the bid evaluation from the individuals preparing the bids.235
The Commission has repeatedly stated its desire to develop a functional competitive energy market in California, and as noted earlier in this section, we are in the process of implementing a number of programs and safety mechanisms in support of this end state. In the interim, we are operating in an evolving "hybrid market," and the issue at hand represents one of the challenges posed by such a market.
In D.04-12-048, IOUs were instructed to compare UOG and IPP bids, but UOG bids were capped at initial offer costs, and a 50/50 savings sharing mechanism required that ratepayers and shareholders split any cost savings associated with the IOU delivering the project under budget. The IOUs and other parties have challenged the fairness of this requirement and requested that the Commission revisit this requirement, and this issue is addressed in subsection 4.1.4.
The PD disallowed any form of UOG bidding into competitive solicitations until a functional, transparent methodology for comparing the bids on a level playing field has been established. This prohibition was supported in comments by the IPP community, CLECA, SCE, and several other parties. However, a number of parties reference in their comments recent RFOs in which robust mechanisms for comparing PSA and PPA bids were developed and implemented, and the processes were deemed fairly and successfully administered by the PRGs, IEs, and this Commission.
We are sufficiently convinced by these arguments - and particularly by the positions articulated by TURN and DRA - that, recognizing the additional safeguards adopted in this decision regarding IE, PRG and ED oversight of the RFO development process, we will relax for the moment the proposed restriction to exclude head-to-head competition between PPAs and PSAs (and in appropriate circumstances, EPCs). However, we reiterate that, as a precondition for conducting an RFO seeking utility ownership options, the IOU, in conjunction with its IE, PRG, and ED staff shall develop a strict code of conduct - to be signed by any and all IOU personnel involved in the RFO process - to prevent sharing of sensitive information between staff involved in developing utility bids and staff who create the bid evaluation criteria and select winning bids.236
We will not, however, permit IOUs to recoup from ratepayers any bid development costs associated with losing PSA or EPC bids, in the event that any such costs are incurred.
We have insufficient experience at this time regarding how the different qualitative and quantitative attributes associated with straight Utility build bids and IPP bids that are identified in D.04-12-048 (performance risk, credit risk, 10-year versus life-of-asset price terms and operational flexibility) will be reconciled in order to perform meaningful, apples-to-apples comparisons of Utility build and IPP bids, so we retain the prohibition on Utility build bids in competitive RFOs at this time. 237
We encourage interested parties to introduce well-developed proposals in the 2008 LTPP proceeding that address the issues raised in D.04-12-048 and, at a minimum, the following additional concerns:
· How IOU bid development costs, particularly for unsuccessful bids, would be addressed (e.g., are these costs "at-risk" or are they ratepayer-guaranteed?);
· To the extent that penalty and reward components are added to UOG bids to make them more consistent with IPP bids, whether and how limits would be placed on the participation of the IOU's ratebased resources on the proposed project (i.e., what would prevent an IOU from re-directing its ratebased staff and other resources well in excess of the amounts estimated in its winning bid); or
· What further measures (outside of, or in addition to, those highlighted in this decision)will be taken to prevent sharing of sensitive information between staff involved in developing utility bids and staff who create the bid evaluation criteria and select winning projects?
We agree with parties and find it important to recognize that even the perception of bias in an RFO can be sufficient to dampen participation from other potential non-utility investors and developers are less likely to get support from capital markets if there is a perception that merchant bids will be undermined by utility built or affiliate projects. In order to address this bias issue - whether perceived or real - we have established many "checks and balances" on the front end and back end of the RFO process.238 Our goal with these additional safeguards is to eliminate any potential for impartiality at any stage of the RFO process - whether that RFO is seeking PPA only bids or merchant and utility owned bids.
Among those parties who feel that the development of new UOG outside of the competitive RFO process is appropriate, there are a variety of opinions regarding under what circumstances (and how much) UOG is permissible or desirable.
We want to make it clear that we continue to believe in a "competitive market first" approach. As such we believe that all long-term procurement should occur via competitive procurements, rather than through preemptive actions by the IOU, except in truly extraordinary circumstances.
SCE identifies three specific instances in which it envisions developing UOG rather than procuring from the market: grid reliability projects (e.g., a local reliability resource in a load pocket to mitigate market power), fuel diversity (development of a nuclear or Integrated Gasification Combined Cycle (IGCC) resource that it does not expect the market to develop), or as a market backstop (in the event that some facet of the market is not working as anticipated). PG&E and SDG&E identify a broader role for new UOG as, essentially, one of the procurement tools they can utilize to provide the best value to ratepayers in competitive RFOs or outside of the RFO process.
IEP recommends that all long-term procurement should occur via competitive procurements, rather than through preemptive actions by the IOU, except in truly extraordinary circumstances. NRG recommends that the Commission adopt a "Competitive Market First" policy in which utilities are required to demonstrate that they have solicited market alternatives before being allowed to pursue utility-built or affiliate-built turnkey options.
TURN states that UOG should only be proposed if it meets one of the following criteria:
· The project was chosen in the course of a competitive solicitation.
· The utility had conducted a competitive solicitation within the previous 12 months and found no (or insufficient) bids to be acceptable from a ratepayer perspective.
· The project resulted from a unique opportunity.
· The project was required to fulfill a specific system or portfolio need that could not reasonably be expected to be met via a competitive solicitation.
The Commission is committed to developing a functional competitive energy market in California, and under the current hybrid market we have a strong preference for competitive solicitations for generation. However, as noted by several parties, unique circumstances could arise that dictate a need for UOG outside of a competitive RFO. Both SCE and TURN offer reasonable proposals for unique circumstances in which UOG outside of a competitive RFO may be the most attractive option to ratepayers for resource development.
At this time, we divide the unique circumstances warranting some form of utility ownership into five categories.239 Below, we list and describe each category. Because the Commission has a strong preference for competitive solicitations, in all cases, if an IOU proposes a UOG outside of a competitive RFO, the IOU must make a showing that holding a competitive RFO is infeasible:
· Market Power Mitigation - the IOU must make a strong showing that as a result of some attribute of the desired resource, a private owner would have the ability to exert significant influence over the price of its development or of the price and quantity of its output (energy, capacity, or ancillary services);
· Preferred Resources240 - while we continue to rely on markets to deliver efficiently priced products for ratepayers, we see no reason to limit our options and intend to continue to deploy all resources available to us, including utility development and ownership, to meet California's vital environmental policy objectives;
· Expansion of Existing Facilities - we can envision certain unique circumstances in which ratepayers would benefit from development on or expansion of an existing IOU asset that would not lend itself to the PPA project structure, but the IOU would need to make a strong showing that such development were clearly preferable to a resource that could be obtained via a competitive solicitation that would not necessarily result in utility ownership;
· Unique Opportunity - an attractively priced resource resulting from a settlement or bankruptcy proceeding (we anticipate that these opportunities will diminish over time);241 and
· Reliability - resources needed to meet specific, unique reliability issues (particularly under circumstances in which it becomes evident that reliability may be compromised if new resources are not developed, and the only means of developing new resources in sufficient time is via UOG.
We shall consider these unique circumstances for UOG approval outside of a competitive solicitation on a case-by-case basis via an IOU application. In instances in which an IOU submits an application for UOG that falls into one of the above categories, the IOU should request in its application to hold a competitive RFO for turnkey project development of the resource (a PSA). If a competitive solicitation for a PSA contract to build the UOF is not appropriate, in its application the IOU should explain why this is the case and propose either an EPC or straight utility build project approach, depending on the circumstances.
Finally, several RFOs have required or provided as an option the transfer of the fully depreciated resource underlying a PPA to the IOU. We believe that this practice distorts the market, and we prohibit IOUs from including this approach as an option in their competitive RFOs.
We again express our support for our "competitive market first" approach. By taking these steps we believe we are moving further along in our transition to a robust competitive generation market. We firmly believe that all long-term procurement should occur via competitive procurements, except in truly extraordinary circumstances. While we do not explicitly disallow utility ownership options in the generation market we continue to look unfavorably on this procurement option but realize that in extraordinary times this may be the optimal method for meeting the needs of California's ratepayers.
As previously noted, D.04-12-048 required IOUs to bid utility-build projects into competitive solicitations. For its successful bids, the IOU was not allowed to recover "...initial capital costs in excess of its final bid price for utility owned resources."242 This policy has come to be known as the "cost cap" on UOG. The Decision also requires a "50/50 sharing of savings between ratepayers and utilities" for costs that come in under the capped bid.243 Thus, under the present process, if actual construction costs come in below the cap, 50% of the savings are allocated to customers and 50% to utility shareholders. If actual construction costs come in above the cap, utility shareholders are responsible for all cost overruns.
The 50/50 savings sharing related to construction cost savings is an unresolved issue from D.04-12-048 following a decision granting rehearing on SCE's Application for Rehearing.244 The 50/50 savings sharing issue was originally set on its own track in this proceeding, with a separate schedule for its discussion and possible resolution. The interested parties exchanged proposals and had meetings and reported back to the proceeding that the issue should properly be part of the whole LTPP since it was inextricably intertwined with procurement.245
Although parties disagreed about many issues associated with this mechanism, including the appropriateness of a cost cap altogether, there was general agreement (among parties who believe that UOG is appropriate at all) that the "50/50 sharing mechanism" is not workable and should be eliminated. They argue that, on its surface the asymmetric risk sharing is unreasonable - that is, shareholders bear 100% of all risk of cost overruns but are only eligible for 50% of any potential benefits from completing a project under budget. Generally, parties who are open to UOG believe that neither utility ratepayers nor utility shareholders should bear asymmetric risk.
PG&E proposes that the Commission adopt a flexible approach to ratemaking for utility-owned generation. In particular, when a utility-owned project is chosen in a competitive solicitation and presented to the Commission for approval, the utility would propose an appropriate ratemaking approach. The Commission could then accept, reject or modify the utility's ratemaking proposal. PG&E's proposal is based, in part, on the utility-owned projects approved by the Commission to date, which have adopted a number of different ratemaking mechanisms.246 PG&E argues that, by allowing utilities the flexibility to propose differing ratemaking mechanisms for utility-owned projects, the Commission will avoid a rigid approach and be able to determine the ratemaking for a specific facility that has the greatest customer benefit.
PG&E believes that traditional cost of service ratemaking is preferable in most situations. It provides for Commission oversight of the cost of owning and operating the facility, and provides the utility with the opportunity to recover any costs the Commission finds reasonable. Traditional cost of service ratemaking is intended to carefully balance the risks and rewards of new utility-owned generation between customers and utility shareholders, and is appropriate in a wide range of situations. In an application for approval of utility-owned generation, the utility could propose cost of service ratemaking for a specific facility where this kind of ratemaking would be beneficial for customers and the utility.
SCE argues that the Commission should replace the solicitation-cost-cap-50/50 sharing mechanism framework in D.04-12-048 with the comprehensive framework that SCE set forth in Volume 2 of its LTPP and in supplemental testimony.247 Under the scenarios SCE presents it argues that the UOG projects should not be subject to a cost cap. In many instances, IOUs will be acquiring new projects to advance cutting-edge technology, or to maintain reliability of the system. In sum, SCE states that the Commission has provided some flexibility in cost recovery mechanisms and should continue to recognize that certain modifications to the framework set forth in D.04-12-048 are necessary.
SDG&E recommends that the Commission adopt a framework where bid prices for both UOG and IPP generation are fixed upon submittal of the project to the Commission for approval. Additionally, SDG&E recommends that the Commission adopt a modest incentive mechanism to be used for treatment of cost savings and overruns.
Under the methodology outlined in D.04-12-048, a bid for utility-owned generation is frozen once entered into a solicitation. SDG&E states that there are numerous reasons why bid prices might legitimately change for both utility-owned and merchant-owned generation after bid prices have been submitted.248 For example, changes in scope, schedule, and force majeure can cause price increases or decreases depending upon the circumstances at hand regardless of ownership. Additionally, risks that are equally present for both merchant-owned and utility-owned projects come in the form of credit, permitting, technology, regulatory, legislative, construction, and operational risks, among others. After bids are tendered, contractual language in PPAs is negotiated and agreed upon to balance these risks and allow for fair resolution.
SDG&E argues that under the current framework utility shareholders are exposed to higher risks from scope and schedule refinement. Holding merchant projects to their initial bid price eliminates this risk disparity, but creates the same problems for merchants as faced by utilities under the present mechanism. High contingencies and/or extensive exclusionary terms would abound. In the end, it is in the best interest of utility customers to allow a certain degree of price and scope flexibility prior to submittal of projects to the Commission for approval. Otherwise, both UOG and IPP generation bids would contain high contingencies to cover the greater risks.
Furthermore, SDG&E believes that holding the utility shareholders alone as responsible for these greater risks will essentially preclude utility ownership as a viable option and eliminate SDG&E's claimed cost-of-service benefits.249 Instead, as a true measure of fairness, both utility and merchant-owned generation bids should follow the process whereby the utility submits final bids and contracts to the Commission for approval. Any changes to the price or material changes in terms between the initial bid and submittal to the Commission for approval should be fully investigated by the IE, the Parties to the proceeding and by Commission staff for both utility-owned and merchant-owned generation.
TURN claims that different UOG projects create different risks from a ratepayer standpoint. In some cases the initial capital cost (which was the focus of the cost cap and 50/50 sharing policy adopted in D.04-12-048) may be the most important risk to mitigate from a ratepayer standpoint. But in other cases heat rate and unit availability may be more important in the long run, or the future trend in O&M expenses and/or capital additions over time. All of these factors need to be considered in coming up with an appropriate set of ratemaking incentives and penalties for a particular utility-owned project.
TURN notes that ratemaking mechanisms to mitigate the cost and performance risks to ratepayers of a UOG project can take many forms in different situations. One example is the "cost cap" approach adopted in D.04-12-048, under which the utility is not allowed to recover initial capital costs above the forecast that was the basis for the selection of the project. This could also include a "cost sharing" formula such as that adopted in the settlement approving PG&E's acquisition of the Contra Costa Unit 8 (now known as "Gateway") project from Mirant. In other cases, such as the Edison Mountainview acquisition and SDG&E's purchase of the Palomar plant, the Commission has adopted heat rate and/or plant availability incentive mechanisms, under which the costs resulting from deviations above and below a benchmark level of performance are shared between the utility and its customers based on an established formula.
TURN contends that these mechanisms provide a tangible incentive for the utility to operate the plant efficiently, and protect ratepayers to some degree against the economic impacts of poor plant performance over time. By listing these various possibilities, TURN does not intend to preclude the adoption of creative new approaches that achieve the same basic objective of ratepayer risk mitigation in the case of utility-owned generation. Regardless of the approach taken, TURN emphasizes that what is most important is that the IOU be required to justify the requested rate treatment in any application proposing a UOG project.
Parties propose that the Commission adopt a more flexible approach to ratemaking for UOG, rather than trying to establish a single approach (such as a cost cap and 50/50 savings sharing) that would apply to all projects regardless of the specific circumstances. Given that UOG projects may be developed to satisfy a variety of concerns, such as local reliability constraints, specific CAISO operational needs, or for meeting various regulatory mandates (RPS, AB 32, etc.), some parties state that the Commission should establish equally flexible ratemaking.
The three broad categories of ratemaking alternatives that the Commission could consider for UOG are discussed below. Essentially all possible ratemaking approaches are represented by one or a combination of these categories.
Cost of service ratemaking provides for Commission oversight of the cost of owning and operating the facility, and provides the utility with the opportunity to recover any costs the Commission finds reasonable. Traditional cost of service ratemaking is intended to balance the risks and rewards of new UOG between customers and utility shareholders, and has been used in a wide range of situations. In an application for approval of UOG, the utility could propose cost of service ratemaking for a specific facility where this kind of ratemaking would be beneficial for customers and the utility.
The concern with this approach is that there is an asymmetric incentive for the IOU. Any savings incurred in developing the project results in a decrease in capital expenditures for which the IOU does not receive a return on investment, while the IOU does receive a return on any cost overruns for which it receives Commission authorization.
Another alternative would be to adopt some schedule for sharing (between ratepayers and shareholders) of cost savings or overruns. This schedule could be as simple as the 50/50 sharing approach adopted for project cost savings in D.04-12-048 (applied to cost overruns, as well, if symmetric risk/reward were desired), to the structure employed in the Gateway settlement to address relatively minor capital cost overruns,250 to SDG&E's proposed limited risk and reward incentive mechanism with symmetrical dead bands and shareholder rewards/penalties.251
The final alternative would be a cost cap in which any cost overruns would be born strictly by the IOU shareholders. Similarly, any savings resulting from a below-bid final construction cost would be passed on to shareholders. This represents the risk/reward regime faced by IPPs who bid into RFOs.
We agree with parties that flexibility in procurement is critical to obtain the best resources for customers. Commensurate flexibility in ratemaking associated with the new generation resources is also important, as we agree that providing for ratemaking flexibility will facilitate the development and construction of a broader range of generation facilities that should benefit all customers. We concur with parties that a "one-size-fits-all" ratemaking regime is not desirable and that the "50/50 cost cap" directed in D.04-12-048 should be eliminated.
We will consider cost-and savings-sharing ratemaking mechanisms such as those utilized by PG&E or proposed by SDG&E on a case-by-case basis, based on the unique circumstances associated with the procurement, and proposals for the requested treatment must be justified by these unique circumstances.
We agree with SDG&E that bids received in RFOs should be fixed upon submittal to the Commission for approval. For the reasons explained by SDG&E, though, we also agree that there are legitimate reasons why a bid price might need to be adjusted between the time it is originally submitted into a solicitation and the time it is finalized and brought to the Commission for approval. Limiting bids to the initial offer price, and subsequently ignoring any changes to the terms and conditions of the deal, will undoubtedly lead to increased costs for consumers due to the need for entities to anticipate contractual negotiation risk and therefore price that risk into the initial bid.252
4.2. Procurement Rulebook
As part of its LTPP filing SCE included a "Procurement Rulebook" as Volume III. SCE states that it developed the Procurement Rulebook in order to further its goal of remaining in full compliance with its Commission-approved AB 57 procurement plan and all Commission rules and guidance that relate thereto.
ED staff held a workshop on the need for and potential design of a Procurement Rulebook on May 23, 2007, and at that time parties agreed to establish a Rulebook Working Group (referenced in ALJ Brown's June 29, 2007 ruling) to assist ED staff with the design and development of a rulebook.
SCE believes the Rulebook to be a useful tool for several reasons. First, because SCE's Commission-approved LTPP consists of guidance and rules that is dispersed among various procurement plan filings, decisions, rulings, advice letters and advice letter approvals, SCE feared that an employee could inadvertently violate a rule of which he or she were unaware or which had been since modified. SCE argues that employees would benefit greatly from having all of the rules in one place and in an organized fashion.
Second, SCE believes that because the rules governing its procurement activities were scattered across various filings, it was possible that some of the rules could be in conflict with each other. Therefore, SCE contends that an organized Rulebook that compiled all of these rules in one place would help identify any conflicts and ensure that those conflicts could be resolved. Third, SCE argues that there could be ambiguities in the rules, and therefore, sought to compile its understanding of the rules so that it could identify any areas of ambiguity and seek clarification from the Commission. Finally, SCE urges that a comprehensive Rulebook would assist the Commission in identifying areas where it wishes to add clarifications or make modifications in order to further its policy goals.
For all of the above reasons, SCE seeks approval of its Procurement Rulebook in this proceeding. In doing so, SCE asks that the Commission clarify any rules that it believes SCE has inaccurately construed and/or identify any rules that it believes have been left out, so SCE may definitively provide the Procurement Rulebook as a guide to its employees in an effort to achieve 100% compliance with its procurement plan. SCE states that once its Rulebook is approved, it will become the implementation portion of SCE's procurement plan and any of its power procurement activities that are compliant with the Procurement Rulebook should be deemed compliant with SCE's procurement plan.
Further, SCE posits that its Procurement Rulebook was designed to be a living document that can be updated in response to changing rules and requirements. SCE proposes that whenever it submits a request to modify its procurement plan or the rules governing its procurement activities, it will submit a redlined version of the affected Rulebook pages, and/or a proposed Rulebook insert incorporating those changes for review and approval along with its request. SCE further suggests that it submit a complete copy of its most current version of its Procurement Rulebook every two years in the LTPP proceeding for review and approval. This combination of procedures will ensure that the Rulebook will always be up-to-date and that any additional new rules and guidance provided by the Commission between procurement planning cycles will be submitted to the Commission for review and approval.
While SCE believes that the Procurement Rulebook has already proven to be very beneficial to SCE in striving towards it goal of 100% compliance with its procurement plan and all related Commission rules and guidance, it does not necessarily believe that each IOU should be required to adopt its own procurement rulebook. SCE recognizes that all three IOUs have developed their own methods of compliance, and does not know whether its method would be compatible with the other systems in place at the other utilities. Thus, SCE asks that its Procurement Rulebook be approved as an accurate compendium of its procurement plan in this proceeding, and will explore the issue of whether this format could also be adopted by the other utilities in the next procurement planning cycle in the Rulebook Working Group, in which SCE has taken a lead role. Should the Commission seek to impose a formal Rulebook requirement on all three IOUs, SCE strongly urges the Commission to issue a ruling on its Procurement Rulebook in this proceeding, rather than hold off on its decision until the next planning cycle.
PG&E agrees that a Procurement Rulebook would be useful for the utilities, the Commission and its Staff, as well as parties interested in utility procurement. The purpose of the rulebook, development, and review by the Commission are all issues which need to be discussed and addressed before development of a rulebook for PG&E can commence.
In comments, SDG&E states that it has no objection to the Rulebook being adopted or approved for SCE's use. However, SDG&E does not support a Rulebook requirement to govern its own procurement activities. Rather, the Commission-approved AB 57 procurement plan represents SDG&E's best interpretation of what the Commission decisions require. The Rulebook, therefore, offers little apparent benefit for SDG&E, and the burden of developing and updating it would be considerable.
SDG&E also questions whether it is truly possible for each individual utility to condense years of Commission decisions and dicta into a satisfactory set of "rules" that the Commission could legitimately approve outside the context of specific factual situations. Many of the decisions in this area have evolved over the years, and they will continue to evolve, so it will be difficult for each utility to ensure that its interpretation of those decisions has conclusively established what all the rules in fact are. SDG&E notes that even if the rules could be established for a period of time, inevitably changes would occur.
SDG&E also argues that another major threshold issue is the extent to which the rules need to be the same for all three utilities. Given the interpretive aspect of developing a rulebook, it is nearly impossible to conceive that accord could be reached among all three utilities about important procurement activities and how the rules apply, particularly when each utility will have its own legitimate reasons for why the rule should be developed or interpreted in a certain way.
If it is intended as an internal reference tool, then SDG&E has somewhat more agreeability towards the concept of a Rulebook, but again finds it to be unnecessary when the Commission-approved plan reflects SDG&E best interpretation of Commission guidance and the plan establishes SDG&E's AB 57 upfront standards. According to SDG&E, the status of the rulebook also needs to be carefully considered: Does the rulebook supersede the Commission decisions from which it is derived? Is it binding on the utility with the same force and effect as its Commission-approved procurement plan or is it a reference tool that is not formally a part of the AB 57 plan? As a binding part of the Plan, developing and maintaining a rulebook would unduly burden and complicate a procurement process that is already laden with regulatory filings and process.
SDG&E understands the basic desire for clarity in this challenging and complex area, but believes the best way to achieve that goal is to perfect the procurement plans themselves. As such, SDG&E strongly advises the Commission not to adopt or require a Procurement Rulebook requirement for SDG&E. If the Commission decides to require a rulebook for each utility, then the next LTPP proceeding is the appropriate forum for such an effort.
TURN believes that the procurement Rulebook created by SCE is a very useful tool for the Commission, the utilities, and the parties active in procurement matters. The development of modified versions for PG&E and SDG&E would be a worthwhile endeavor. However, TURN submits that the rulebook should remain a reference tool, and should not supersede or otherwise supplant the underlying Commission decisions and resolutions upon which the rulebook is based.
The Scoping Memo directed the IOUs to reflect in their 2006 long-term procurement plans all of the procurement-related decisions made by the Commission to date in all other procurement-related dockets. Volume 3 of SCE's LTPP represents the most thorough attempt at fulfilling this directive. For the most part, it is a clear, comprehensive reflection of Commission-approved procurement policy. In its present form, however, SCE's Rulebook cannot be adopted by this Commission. Both ED and Commission legal staff have determined that prior to adoption, SCE's proposed rulebook would need to undergo a number of modifications to (1) correct substantive errors; (2) refine language; and (3) be reformatted to apply to all IOUs. We discuss each category of modification in turn below.
ED and Commission legal staff conducted an initial comparison of the Rulebook with several Commission decisions, and several substantive errors were identified, including an oversimplification of the Commission's adoption of the GHG adder,253 and a misrepresentation of whether to count reliability-must-run units toward resource adequacy requirements.254 Staff did not have the resources to perform a more comprehensive comparison against all relevant Commission decisions, but the results of this initial comparison confirm that this exercise will be necessary prior to Commission adoption of the Rulebook as a tool that ensures compliance with all Commission rules and guidance.
ED's review also determined that SCE's Rulebook frequently deviates from the precise language selected by the Commission. Most deviations seem incidental and insubstantial. For example, whereas the Commission concluded, "In their month-ahead filings, LSEs should be required to incorporate adjustments to their year-ahead load forecasts to account for customer migration," SCE wrote, "LSEs must include load migration adjustments in their forecasts and in their monthly resource adequacy filings." For compliance purposes, such interpretations may get the message across to IOU employees, but they confound the Commission's plain meaning, and thus make a poor substitute for the original decision language.
Consequently, while we believe that the creation and adoption of a "Rulebook" (hereafter referred to as an "AB 57 Procurement Plan Implementation Manual," which more specifically identifies the purpose of the document) will be a useful tool for the Commission, our staff, the staff of the IOUs, and other market participants, we do not adopt SCE's Rulebook at this time. We do, however, direct ED staff to continue the work begun by SCE and work with the IOUs and other interested parties to create a Commission-endorsed "AB 57 Procurement Plan Implementation Manual" for each IOU.
The focus of this process should be to develop an AB 57 Procurement Plan Implementation Manual that contains the comprehensive set of procurement rules, including any IOU-specific requirements, (including an updating procedure) that can be accessed by all interested market participants to determine each IOU's compliance with its AB 57 Procurement Plan.
We envision that this process will answer many of the outstanding questions that have been raised by parties regarding this Implementation Manual, including what authority will the Manual have, how and by whom the Implementation Manual will be updated, etc., and will allow parties to evaluate and come to consensus on various implementation details proposed in the IOUs' 2006 LTPPs that are not ruled on in this decision. ED staff is directed to notice the service list with a proposed schedule for Implementation Manual development within 60 days of the date of this Decision.
4.3. Implementation of AB 1576 and Repowering
AB 1576,255 codified as Section 454.6 of the Pub. Util. Code, gave the owners of aging power plants incentives to repower or replace the plants in lieu of retiring them by providing rate recovery for IOUs entering into contracts for electricity from replacement or repowered projects. Section 454.6 is silent as to implementation details for repowering projects, except to establish the criteria that a project must meet to be eligible for the rate treatment instituted by the legislation.
Mirant, LS Power, SCE, and TURN all submitted proposals in this proceeding for methodologies to implement AB 1576. Based on an ED workshop on repowering and retirements, interested parties formed a Working Group to synthesize one or more "consensus proposals" from the original individual proposals. While the Working Group made significant progress, it did not reach an agreement on all disputed issues. While several parties agreed to certain elements for implementing AB 1576, the agreement is still inchoate and not ripe for consideration by the Commission in this decision.
However, by reviewing the issues that were discussed and negotiated in the AB 1576 Working Group, we are aware of some of the parties' main concerns, which include: the extent to which AB 1576 projects should be afforded special consideration in the RFO process, and if so, how to weigh and evaluate that status; whether there should be a pre-certification process for eligible AB 1576 projects, and if so, what role would the ED play in the certification; how to facilitate the development of repowering and replacement projects meeting the statutory criteria; whether a utility must explain its decision to not select an AB 1576 project from a RFO; and whether potential transmission cost savings are captured in the existing RFO evaluation process.
Most important is the concern that all the benefits of AB 1576 projects are properly considered and evaluated in a RFO - including quantifiable economic benefits and non-quantifiable social and environmental benefits. Mirant urges the Commission to direct the utilities to select AB 1576 projects from their RFOs, unless there is a clear superior economic alternative. While we find Mirant's arguments cogent, because there is not sufficient consensus from the Working Group on the disputed issues, we will not make any new orders concerning the selection of AB 1576 projects from RFOs at this time. We do, however, repeat the direction we provided in D.04-12-048, at p. 145-6, that the IOUs are "...to consider the use of Brownfield sites first and take full advantage of their location before they consider building new generation on Greenfield sites. If IOUs decide not to use Brownfield, they must make a showing that justifies their decision."
To further clarify our directive from the 2004 LTPP decision, IOUs are to consider repowered or replacement options presented in a RFO (i.e., not strictly for UOG projects, as some IOU representatives indicated they had interpreted this directive in D.04-12-048) before they choose options developed on Greenfield sites, or make a showing that justifies their decision not to do so.
Interested parties are urged to continue meeting and negotiating on AB 1576 related issues, and further Commission action on the topic will be deferred for consideration in the 2008 LTPP proceeding.
4.4. Implementation of AB 32 and GHG Issues
On June 1, 2005, Governor Schwarzenegger signed Executive Order S-3-05 thereby establishing California's leadership in and commitment to reducing the negative impacts of climate change. The Executive Order establishes GHG emission targets that call for a reduction of GHG emissions to 2000 levels by 2010; to 1990 levels by 2020; and to 80% below 1990 levels by 2050. The Executive Order also directs California Environmental Protection Agency to lead a multi-agency Climate Action Team to conduct an analysis of the impacts of climate change on California and to develop strategies to achieve the targets and mitigation and adaptation plans for the State. Since that time, these orders have been further refined through the passage of AB 32, which requires the California Air Resources Board (CARB) to promulgate regulations to reach the 2020 goal of reducing total GHG emissions to1990 levels.
As stated in EAP II:
"Climate change is the most serious threat to our environmental future, and demands immediate action. Its symptoms are already evident in California... Increasing energy efficiency, demand response, and renewable resources to the maximum extent possible in California and the western region will further reduce our contribution to climate change."
The Commission has been strongly committed to pursuing a path toward reduced GHG emissions, and the IOUs received their first request to consider the implications of various GHG scenarios in their LTPPs in proceeding R.04-04-003. In their 2004 LTPPs, the IOUs offered a range of responses; however, none provided the profile requested, as they were all moving through the Climate Action Registry's inventory and auditing process.
Although a policy for the reduction of GHGs was not in place at the time of the 2004 LTPP decision (D.04-12-048), the Commission recognized the importance of beginning to plan for the possible effects of a GHG cap. As stated in that decision, "...it is appropriate for us to consider policies that would limit the exposure of IOU ratepayers to risks associated with this future regulation. California, and in particular this Commission, along with the CEC and CPA, has given clear signals of its intent to be the pacesetters in this arena and take positive steps in seeing action on this front."
D.04-12-048 further directed IOUs to employ a GHG adder when evaluating fossil and renewable bids received via an all-source RFO. Consistent with established Commission policy and the positions of several parties, we adopted a range of values to explicitly account for the financial risk associated with GHG emissions of $8 to $25 per ton of CO2, to be used in the evaluation of fossil generation bids.
In the current proceeding, R.06-02-013, the Commission's Scoping Memo provided guidance to the IOUs on the Commission's expectations for inclusion of the impacts of GHG reduction in the 2006 LTPPs. The Commission indicated that the 2006 LTPPs should include the key planning decisions that the utilities would need to make in the next few years in order to ensure that the Commission's energy policy objectives would be maintained and pursued in the future, including reducing GHG emissions to 1990 levels by 2020. This involved including GHG forecasts as part of ten-year resource plans, indicating the methodology and assumptions used in making GHG calculations and ensuring that the LTPP comports with the direction given in AB 32 and SB 1368.
A further modification by the ALJ said that the briefings were to include "planning uncertainty associated with the rules for implementation of AB 32." Also, the Commission is committed to moving procurement decisions further out into the future to "avoid just-in-time procurement activity" and increasing "attention to greenhouse gas forecasts and carbon constraints in the LTPPs."
PG&E asserts that their Increased Reliability and Preferred Resources Plan have slightly lower CO2 emissions than the other two alternative plans at the end of the planning horizon. However, long-term changes in load and resources which are represented in the scenarios increase emission volumes by 15% to 25%, depending on the scenario or plan. Hydro swings contribute to volatility in CO2 emission in a given year.256
PG&E claims that the attribution of an emissions rate to unspecified resources remains unclear, thus it is unknown whether system purchases done on an aggregate or regional basis will pass the EPS or not. PG&E has long-term system contracts among its DWR contracts that will expire during the 2006 LTPP.
PG&E argues that although the actual ramifications of AB 32 are as of now unclear due to regulatory uncertainties, PG&E is committed to maintaining a portfolio emissions rate that is among the lowest in the nation through pursuit of DR, EE and renewable generation.
PG&E acknowledges that its recommended plan may require significant revision and updating in the future to reflect the impacts and requirements of AB 32 and other GHG emissions reduction legislation in the next few years; however, PG&E feels that its recommended plan attempts as practicably as possible to anticipate, consider and incorporate the results and priorities of AB 32. PG&E states that it will inform the Commission and revise its procurement plan as appropriate to reflect the actual requirements of AB 32.
From PG&E's perspective, the Commission should consider focusing on one GHG reduction goal consistent with state policy, rather than creating further separate targets in renewables, DG, solar roofs, DR, repowering or EE. Increased flexibility in choosing among a suite of GHG reducing tools should result in reaching policy objectives at a much lower cost than if specific targets are created in several programs.
SCE, however, contends that the main impact of applying a GHG Emissions Performance Standard (EPS) to contracts greater than five years will be a continued and higher reliance on natural gas because the EPS eliminates new coal contracts. SCE feels that this will result in higher utility prices for customers.257
SCE acknowledges that R.06-04-009 is addressing the implementation of an "Interim Emissions Performance Standard Program Framework," and at such time that a decision is in place, SCE will have a better understanding of how the EPS will affect procurement practices and may need to update its Procurement Plan or other testimony.
SDG&E presents its estimated total (metric tons/year) and rate (tons/GWh) of GHG emissions in its LTPP. They acknowledge that the amounts are estimates since the Commission has not yet developed official measurement and reporting protocols for all types of generation sources; however, overall GHG emissions decline over the procurement period. SDG&E estimates that its emissions will drop by 1 MMTCO2E258 over the planning period.259
SDG&E urges the Commission to use a flexible compliance mechanism to meet GHG targets and to take a leadership role in the creation of international trading mechanisms. SDG&E also recommends that the Commission work with sister agencies in implementing the State GHG policy. The utility sector should not be required to undertake mitigation (and impose the associated costs upon customers) that is disproportionate to the energy sector's contribution to the State's GHG emissions. If the utility reduces more than its proportionate share, it should be allowed to sell excess GHG reductions to those entities that cannot meet their reduction obligations through technological fixes applied within their industry. This would allow ratepayers to be compensated for over-compliance and may incent IOUs to do as much as possible to realize ratepayer value from such efforts.
Aglet recommends that the GHG adder that is currently required to be included in contracts over five years in duration (D.04-12-048) should be applied to contracts of more than one year in duration. Aglet believes that the adder has a positive effect on IOU procurement activities through the selection of efficient plants with low GHG emissions.
AReM believes that SCE's concerns about high compliance costs would be better addressed by flexible compliance and market-based solutions (e.g., GHG credit trading), as recommended by SDG&E. AReM also recommends that the Commission reject SCE's proposal to use the CAM adopted in D.06-07-029 to recover from all customers the costs of new generation resources that are procured to meet GHG emissions reduction requirements. AReM states that GHG limits are not a requirement to procure new resources, rather they are a mandate to reduce GHG- a mandate that all LSEs must meet. Since all LSEs will bear their own compliance costs, it would be unfair to allow the IOUs to spread such costs to DA customers as that would require those customers to pay twice for GHG compliance- once to their ESP, and a second time to their local IOU.
DRA urges the Commission to direct the utilities to present a probabilistic analysis of the carbon impact of their plans incorporating the $8 per ton price adder that represents the "avoided cost value" of carbon in new physical resources. DRA believes that without such analyses, the long-term plans leave a significant cost volatility associated with GHG unanalyzed, thereby introducing an unknown amount of unqualified price risk into the proposed LTPPs. DRA mentions that the IOUs have undergone similar analyses for other factors in the LTPPs (i.e., managing market price volatility risk, hydro availability risk, etc.) in order to place the utility in a position to meet the CRT expectations as measured by the TeVaR; therefore, there is no reason they should not do the same for the GHG impact. DRA's proposed probabilistic analyses would refine the $8 per ton adder rather than replace it. They suggest a low, middle and high projection developed using a Delphi methodology or other nominal group process. DRA believes that a probabilistic analysis of future carbon risk would capture the uncertainties surrounding the future development of carbon policies in California and around the world better than the $8 per ton single price model. DRA notes that all other types of future risk hedging in the LTPP are done with probabilistic projections rather than a single price trajectory.
CEERT recommends that the Commission find that the IOUs 2006 LTPPs do not comply with the GHG emission reductions mandated in AB 32 nor do they plan for "uncertainties" in AB 32 GHG regulations. While utilities were mandated to plan for uncertainties associated with the implementation of AB 32, CEERT believes that Commission policy also mandates that the IOUs submit LTPPs that are on course for reducing GHG emissions. CEERT argues that the IOUs did not effectively demonstrate how and to what extent the IOUs will achieve California's mandated GHG emissions reductions. The three IOUs, while acknowledging Commission and legislative actions, state that there is too much regulatory uncertainty to plan or account for GHG emissions reductions in the LTPPs.
In D.04-12-048, the Commission adopted an NRDC proposal to require the IOUs to "develop and implement a comprehensive GHG reduction plan in their (2006) LTPPs, which include "resource scenarios" that allow comparison between existing and expected GHG emissions characteristics of the utilities' portfolios with and without the new resource additions proposed in the procurement plans. D.06-02-032 directed the IOUs to establish a baseline for the GHG emissions cap on a historical basis, with 1990 as the preferred referenced year. For the 2006 LTPPs, IOUs were directed to include information about existing GHG emissions profiles and future GHG emissions of their procurement plans.
CEERT initially recommended that the Commission order the current LTPPs be amended to reflect the changes in resource planning that will be required to achieve AB 32 goals and mandates. Given tight deadlines and the fact that GHG implementation rules will be developed in Phase II of the GHG proceeding (R.06-04-009), CEERT recommends that the Commission provides instructions to the IOUs in the 2006 LTPP decision as to the planning approach to be used by the IOUs in their 2008 LTPPs to ensure AB 32 compliance for the 2009-2019 planning period.
CEERT, along with DRA, believes that given the compressed time between approval of final 2006 LTPPs and IOU filing of 2008 LTPPs, the Commission should limit the approval of procurements in this cycle to those that must be initiated prior to the next LTPP cycle, so that "policymaking development... can inform the next LTPP proceeding" regardless of "planning uncertainties" If IOUs wait until a final AB 32 GHG emissions cap is in place to even begin planning for changes, there will not be enough time left to meet AB 32 GHG reduction goals.
CEERT believes that a key method for reducing GHG emissions is to actively plan for and meet the 33% renewables target for 2020, and that these mandates, while separate, are inextricably linked. CEERT also believes that express direction should be included in the 2008 LTPPs to analyze scenarios that focus on GHG emissions reduction.
CEERT suggests that the Commission should direct the IOUs to analyze and include into their 2008 LTPPs three basic supply scenarios that can be expected to achieve AB 32 goals and targets to be established by the Commission and/or CARB (using portfolio analysis). These scenarios meet the goals of (1) providing projections on the flexibility allowed in meeting targets, and (2) producing an energy resource mix that results in emissions at or below required levels and includes realistic assessments of generation projected to be procured from existing, commercially available technologies:
· A least-cost scenario that increases renewable energy content on a trajectory that could reasonably be expected to result in increasing the utility's renewable energy content to 33% by 2020.
· A least-cost scenario that reduced GHG emissions on a trajectory that could reasonably be expected to reduce the utility's GHG emissions to the utility's 1990 levels by the year 2020.
· A least-cost scenario that reduces GHG emissions on a trajectory that could reasonably be expected to reduce the utility's GHG emissions to 90% of the utility's 1990 levels by the year 2020.
GPI contends that an important question that must be asked is whether the limitation of greenhouse gasses through a strong incentive mechanism consistent with AB 32 can be used to achieve all of the preferred procurement goals simultaneously (i.e., EE, RPS). GPI feels that using GHG reduction as a unifying theme of procurement policy would help to ensure that all utilities control their costs to consumers while pursuing an overall program of preferred procurement; however, they recognize that more research is needed into the subject. Until such time as further research is conducted, GPI recommends that the Commission continue to pursue its established preferred resource programs (EE, renewables, etc.) while developing an overall program of GHG limitation.
In response to the IOUs' arguments that a GHG program should not distort the electricity market, GPI states that the essential purpose of AB 32 is to change the state's electricity markets in fundamental ways. It is necessary for the IOUs to expand the bundle criteria by which they judge the efficiency of resource choices to include considerations of carbon content in addition to the traditional considerations of cost and logistic factors. IOUs should take carbon intensity into account as an essential component of the decision matrix used to select resources.
NRDC wants the Commission to require SCE to include in its LTPP its current and forecasted absolute GHG emissions under various scenarios stating that SCE failed to do so in its initial filing. SCE presents a forecast of GHG emission rates on a pound per MWh basis instead of presenting current and forecasted GHG emissions. NRDC states that while SCE presents a forecast of declining emissions rates, there is no information about whether absolute emissions will increase or decrease over the 10-year period. NRDC feels that it is impossible to adequately evaluate SCE's plan given this methodology.
NRDC also suggests that the Commission should require the IOUs to utilize portfolio analysis in developing their 2008 LTPPs stating that such methodology allows the IOU to assess potential changes to a portfolio's risks and costs brought about by adding assets that have their own individual risk and cost profiles. At a minimum, the Commission should require the IOUs to provide detailed information about resource types planned for and the emissions characteristics of the preferred plan compared to other resource scenarios.
NRDC claims that the Commission needs detailed information about planned resource fuel and technology types in order to determine whether the IOUs' emissions trajectory will meet the goals of AB 32. Such planning allows the Commission to answer the following questions: If the path outlined is pursued, what will California's fuel mix be in 10 years? Will it be adequately diverse? What will be the overall cost to customers? What risks will customers face? Will the environmental impacts associated with the electricity industry increase or decrease?
WEM recommends that the Commission not approve any 2006 LTPP that does not make some adjustment for or accommodation to AB 32. WEM notes that PG&E's preferred procurement plan, despite having lower emissions than the other submitted, would result in 15% to 25% more GHG emissions in 2016 than in 2006. WEM states that Scenario 4, which is PG&E's basis for the 2,300 MW resource request, has the least reduction in GHG emissions. In fact, WEM feels that PG&E's assertion that all plans would result in reduced GHG emissions is false; Scenario 2 and Scenario 4 result in increased emissions. WEM is especially concerned that PG&E's 2,300 MW resource request will be primarily powered by natural gas. WEM is also concerned that in the future, this natural gas may be supplied in part by liquefied natural gas (LNG), a fuel that has large upstream GHG emissions that overwhelm the claimed reductions in emissions. In particular, the claimed reductions in the Preferred Plan under Scenario 4 and the Basic and Increased Reliability Plans under Scenario 3 are so slim that introducing LNG could result in significant increases in GHG.
IEP states that the Commission should affirm during the transitional period when information needed to estimate future costs is unavailable, GHG regulations are covered by the PPA's change in law or force majeure provisions, and that costs that the supplier reasonably incurs in purchasing necessary GHG allowances or otherwise complying with future GHG regulations are appropriately passed through to ratepayers.
The Commission indicated that the 2006 LTPPs should include the key planning decisions that the utilities would need to make in the next few years in order to ensure that the Commission's energy policy objectives would be maintained and pursued in the future, including reducing GHG emissions to 1990 levels by 2020. Furthermore, this proceeding directed the IOUs to include GHG forecasts as part of their 10-year resource plans and to specify which methodology and assumptions they used to make their GHG calculations. In addition to evaluating their plans for minimizing environmental impacts, the IOUs were explicitly directed to weigh the ratepayer costs and reliability impact of each proposed plan.
We find that all three LTPPs could have been strengthened by building into their calculations of future need for electric resources a methodology for analyzing the GHG implications of the different resources the IOUs can utilize to fill that net short position. While the implementation details are still under consideration in R.06-04-009, it appears improbable that the IOUs can reduce their carbon emissions from electric generation resources back to 1990 levels without a focused reliance on preferred resources. We share the concern raised by many Intervenors that the IOUs are filling, and are projecting to fill, their respective net short positions with conventional base-load resources so that either there is no room in an IOUs' portfolio for other resources, or the conventional resources will be obsolete and result in large stranded costs. We agree with CEERT that while utilities were mandated to plan for uncertainties associated with the implementation of AB 32, Commission policy also mandates that the IOUs submit LTPPs that are on course for reducing GHG emissions.
The IOUs did not fully comply with the Scoping Memo's requirements to account for AB 32 in their procurement plans. All IOUs offered emissions projections, and PG&E evaluated ratepayer cost versus reliability; however, the plans could have been strengthened by undertaking a vigorous analysis of the potential procurement impacts of operating in a GHG-constrained landscape. While it is true that many of the major decisions have not yet been made regarding the elements of the GHG cap, the utilities should be actively engaged in projecting absolute emissions for various procurement scenarios, estimating the costs of those plans for various GHG allowance prices, and making procurement decisions based on these assessments. Regardless of the ultimate specifics of the GHG cap, it is apparent that to help the State reach 1990 GHG emission levels, the IOUs will need to "raise the bar" on their loading order procurement when filling net short positions. Procurement of zero- or low-GHG resources should be given preference over other resources since these are the types of resources that AB 32 regulations will favor. Also, as discussed in the need determination section of this decision, we will require the IOUs to provide ED and the PRG with a description of the resources they are soliciting based on the procurement authority granted in this decision and how these resources support its transition to a GHG-constrained portfolio.
To further flesh out IOU plans for GHG reductions, we will provide directions in upcoming LTPP proceedings concerning the development of a consistent evaluation of the costs and risks of GHG-reduction to be included in the subsequent LTPPs. These analyses will be based on the recommendations provided by CEERT in this proceeding, modified based on the results of Phase II of D.06-04-009.
The Commission agrees with NRDC that the analyses presented by the IOUs should be detailed enough to enable adequate analysis of fuel mix under various scenarios, overall cost to customers, risks faced by customers and environmental impact. When building the requirements for the future LTPPs, we will consider DRA's recommendation that IOUs employ a probabilistic analysis of the carbon impact of their plans in order to ensure that the significant cost volatility associated with GHG is thoroughly analyzed. We anticipate that Phase II of D.06-04-009 will provide guidance on an appropriate range of costs for this evaluation.
We agree with SCE that plans may require modifications based upon the outcome of D.06-04-009, but as stated earlier, this is not a sufficient reason to delay fully planning for GHG reductions. We support GPI's assertion that the essential purpose of AB 32 is to change the state's electricity markets in fundamental ways. IOUs should take carbon intensity into account as an essential component of the decision matrix used to select resources.
We acknowledge that the IOUs did provide an estimate of overall GHG emissions for the 2006 planning horizon; however, a great deal of inconsistency existed between plans on forecasting methodology employed. To provide clarity going forward, the Commission adopts NRDC's suggestion that all three IOUs be required to provide absolute GHG emissions under various scenarios. In order to accurately measure overall emissions of proposed LTPPs, absolute emissions are necessary along with cost implications of those emission levels at various price points for CO2 allowances.
PG&E and SDG&E request that the Commission allow for maximum flexibility for compliance with AB 32 by using GHG reduction goals as an overarching state policy superseding all existing EE, RPS and DG requirements. GPI supports this approach but acknowledges that until such time as enough research is conducted into the subject, the Commission should continue to follow the current trajectory. While procedures may change in the future, for now, existing legislation mandates compliance with these programs and we will continue to operate under these guidelines. Thus, IOUs are responsible for meeting the goals of each respective State mandated energy program. It goes without saying, though that the actions mandated by each of these programs will assist the IOUs in meeting their GHG requirements. The scenario analyses the IOUs develop need to ascertain what mix of procurement choices beyond these mandated actions will maximize GHG reductions at the least cost to ratepayers.
We acknowledge SDG&E's concern that the electricity industry should not be made to overcompensate for other sectors in meeting AB 32 goals or should be duly compensated for doing so. This is a matter that requires further research and analysis; however, it is best addressed in the GHG proceeding and is out of the scope of this proceeding. We further acknowledge SDG&E's request that the Commission take a leadership role in the creation of international trading mechanisms, and this idea is also best addressed in the GHG proceeding.
Regarding SCE's concern about the considerable cost of new renewable sources that is attributed to transmission, we agree that sufficient transmission is of the utmost importance to the development of renewable energy. The State of California is addressing this issue through renewable energy transmission planning, and it is therefore out of the scope of this proceeding. We also acknowledge IEP's suggestion that the costs that the supplier reasonably incurs in purchasing necessary GHG allowances or otherwise complying with future GHG regulations are appropriately passed through to the ratepayer; however, we believe that at this time it is premature to make such a ruling without regulatory certainty. This issue is more appropriately addressed within the GHG proceeding.
Finally, we agree with AReM that each LSE will be responsible for meeting the ultimate GHG compliance requirements, and the CAM developed in D.06-07-029 for system reliability should not be utilized to pass along any costs associated with achieving reductions on behalf of the IOUs' bundled customers to other non-bundled customers. However, to the extent that an IOU procures a resource for system reliability that is also consistent with the direction of state GHG policy, this cost is certainly recoverable from all benefiting customers through the CAM.
4.5. The 33% Renewables Target
California has taken a progressive and forward-thinking approach toward the achievement of reduced greenhouse gas emissions and increased renewable energy procurement. The Scoping Memo in this proceeding directed the IOUs to describe how the EAP II goal of 33% renewables by 2020 will be achieved. In particular, Key Action # 5 of EAP II requires that IOU's "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." D.04-12-048 FOF #55 further supports a 33% renewable stretch target: "We find that RPS targets are a floor-not a ceiling. The EAP loading order places renewables above conventional generation."
PG&E believes that the Commission should not at this time establish goals beyond 20%. PG&E states that further analysis and study of policy goals, feasibility, and cost impacts is necessary before the current 20% RPS goal is exceeded. PG&E suggests that the Commission should consider combining the GHG reduction and renewable achievement objective goals by setting a GHG reduction goal and allowing the IOUs flexibility in how that goal is achieved. Furthermore, PG&E recommends that the Commission should explore incentives as a more effective mechanism through which to achieve expanded RPS goals. PG&E also suggests that the Commission should work with the CEC and IOUs to explore the operational feasibility of any goal beyond 20%.260
PG&E further requests that the Commission approve its proposal for an Emerging Renewable Resources Program or "ERRP." PG&E states that ERRP is a funding mechanism through which PG&E can assist in the demonstration of the commercial viability of emerging renewable resources beyond its 20% RPS goal. PG&E requests that the ERRP initially be authorized as a two-year program with a maximum budget of $30 million subject to balancing account recovery.261
SCE states that SB 107 specifically left intact existing law which prohibits the Commission from requiring an LSE to procure additional renewable resources in a year following a year in which the LSE achieves the 20% standard. Thus, increasing the level of procurement beyond 20% to 33% would require additional legislation.262
SCE contends that reaching 33% renewables is potentially feasible provided that sufficient transmission exists to accommodate this build out of resources. However, SCE notes that both transmission and the increasing price of renewable energy could render a 33% goal extremely costly.263 For the scenarios provided, SCE has assumed that adequate transmission and SEP funding264 will exist to achieve the 33% goal. SCE does not assume that renewable procurement will increase by a fixed amount each year, citing transmission access as a possible hindrance.265 SCE demonstrates plans to reach 33% renewables in each of the SCE and CEC load forecast scenarios; however, SCE acknowledges that many uncertainties could potentially hamper the viability of this forecast, including: potential fluctuations in load growth due to customer migration; potential fluctuations in renewable output resulting from resource depletion and contract attrition at levels higher than 10% attrition rate assumed for the 33% scenario; delays in obtaining State or local transmission permits; missed milestones by project developers; and other unanticipated causes.266 SCE notes that, to meet a goal of 33% renewables by 2020, SCE would most likely have to pursue contracts with less economic projects that it would otherwise not consider.267
SDG&E supports the Commission's goals expressed in Energy Action Plan II, and that its efforts to reduce GHG emissions include voluntarily expanding its renewable procurement beyond the mandatory 20%. SDG&E states that it plans to increase its renewables beyond 20% in its current LTPP, but the lumpiness of major resource additions makes it difficult to predict exact renewable addition trajectories year over year.268 SDG&E notes that actual procurement as well as SDG&E's possible use of RECs during the course of the plan will likely result in a different resource mix than the one projected. SDG&E argues that whether it is able to achieve a 20% resource mix by 2010, or greater in future years, will depend in part on how contracted resources perform, whether sufficient renewables will be available for purchase by SDG&E, whether SDG&E can procure and count unbundled RECs towards its renewable requirements and whether additional transmission will become available to allow SDG&E to import renewable energy and capacity from outside its service area. SDG&E states that lack of transmission is a major impediment to achieving 20% by 2010 and higher percentages in future years.269
Aglet recommends that the Commission establish a policy goal of 33% renewables by 2020, consistent with EAP II. Aglet argues that until enabling legislation is passed, the IOUs should volunteer to make a good faith effort to reach a goal of 33% renewables by 2020. The Commission should also take action to ensure that the utilities are able to meet the 33% goal. Thus, the Commission cannot require IOUs to meet a 33% renewable goal by 2020 without enabling legislation, but it can establish a policy goal of 33% renewables in this proceeding.270
AReM is concerned that the goal of 33% renewable energy sales will not be easy, if it is even feasible. AReM therefore supports SDG&E's recommendation that the Commission move as expeditiously as possible to approve the use of fully unbundled, tradable RECs for RPS compliance.271
DRA finds that none of the three IOUs provide a plan to continue increasing their renewable percentages after 2010 at a rate which would reach 33% renewables by 2020. This lack of planning does not comply with the State's renewable energy goals as directed by the Commission's EAP II, and it appears to be inconsistent with estimated renewable energy levels that will be required to meet the State's GHG cap as required by AB 32. DRA argues that none of the three IOUs appear to be giving serious consideration to constructing their own future renewable energy sources, although they have constructed and planned natural gas fueled combined cycle and peaking plants.
DRA recommends that the Commission require the IOUs to plan to meet the State's renewable energy goals as directed by the Commission's EAP II and be consistent with the estimated renewable energy levels required to meet the AB32 GHG cap by requiring the IOUs to adjust their plans to continue to move toward the 33% renewable energy by 2020 goal.272
CEERT argues that effective planning by the IOUs to meet the 33% by 2020 target will play a central role in also achieving GHG emissions reductions. CEERT states that the IOUs have largely ignored the direction of the Commission to address the attainment of a 33% renewables target by 2020.273
GPI is concerned that PG&E and SCE oppose instituting the 33% renewables by 2020 goal, though it is an important component of the Governor's energy policy and embraced by EAP II. GPI has long argued that the only compelling rationale for accelerating the State's 20% RPS target deadline from 2017 to 2010 is so that the accelerated goal can be backed up by a higher, longer-term goal for renewables. Otherwise, the policy would result in a quick burst of development activity in the state's renewable energy sector, followed by an abrupt halt. These are not conditions conducive to the development of a stable, sustainable renewable energy industry in the state. Moreover, GPI suggests that the long lead time associated with the 33% goal and the head-start provided by the original 20% goal will actually make it easier for LSEs to reach the 33% by 2020 standard than it will have been to reach the 20% by 2010 goal.
GPI states that PG&E and SCE both argue in their LTPPs that California is experiencing shortages of renewables, which, if true, would put the 33% by 2020 stretch standard seriously in doubt. PG&E's LTPP argues that the pool of reasonably priced renewables is already being depleted. GPI strongly disagrees with the assertion that California is experiencing renewable resource shortages at this early stage of the RPS program. Considering the minimal amount of new renewables development that has actually occurred in California since the enactment of the RPS program, asserting that the pool of renewables is already being depleted is equivalent to saying that the pool was nearly empty from the start.
GPI states that PG&E argues that the coming AB 32 GHG reduction program will provide all of the incentive that the utilities need to continue procuring renewables beyond the mandated twenty percent level, while providing more flexibility in reducing GHGs than is provided by a structured set of specific program mandates (renewables, efficiency, etc.). However, AB 32 rules will not be finalized for several years into the future. Renewable energy generation is a highly capital-intensive enterprise, and in order to sustain a flow of investment capital into the renewable energy sector in California pending the maturation of the AB 32 program, a long-term stretch goal for renewables is highly desirable. Long-term market uncertainty is a major impediment to attracting investment capital. Failure to follow a trajectory towards the 33% stretch goal will jeopardize the ability of the utilities to meet the AB 32 standards throughout the course of the 10-year LTPP planning horizon.
GPI finds that SCE's "Required" plan, which is the plan designed to achieve 33% renewables by 2020, foresees a large amount of biomass development in the out years of the LTPP planning horizon, because carrying a 33% level of renewables in their system would require the stabilizing influence of the additional biomass generators. There is, however, no indication offered about where this biomass will come from, or how. A few pages prior to the above mentioned passage, SCE notes that there is an insufficient amount of biomass resources, either under existing contracts or planned pursuant to the 2003, 2005 and 2006 RPS solicitations, to achieve 20% of the overall ERR portfolio from biomass resources at any time during the planning period. In GPI's opinion, the most important unresolved issue for future biomass development is less one of transmission availability than it is one of resource availability and cost.
NRDC states that PG&E sets a proxy annual renewable procurement target in its preferred plan, the Increased Reliability and Preferred Resource Plan, of 25% in 2016. No analysis is provided as to whether this will put PG&E on track to achieving 33% renewables by 2020, as is required by the Scoping Memo. PG&E only states that it "believes any specific expanded targets, beyond the 20% goal, would be premature until policy goals concerning GHG emissions standards are clarified and a detailed feasibility analysis can be conducted."274
The CEC contends that three of PG&E's four scenarios assume renewable energy procurement at levels below the trajectory that would hit the 33% by 2020 target; only in Scenario 4 was this path realized.275 The CEC argues that SDG&E does not evaluate nor develop a plan to put it on a path to 33% renewables by 2020.276 SDG&E does not explain why its preferred plan does not achieve 33% by 2020 nor does it demonstrate what would need to change to achieve the target. Thus, SDG&E did not comply with the Scoping Memo's direction to demonstrate how they were working towards achieving the 33% policy goal. While SDG&E's plan contemplates increases beyond 20% after 2010, its preferred approach is that future additions should be based on cost-effectiveness, resource fit, green house gas targets, and other factors.277
The State of California is in a unique position to lead the nation in procuring renewable resources and achieving greenhouse gas reductions. Achievement of these aggressive goals, however, requires cooperation and a forward-thinking, innovative approach on the part of all parties involved. Increasing the amount of renewables is a clearly stated component of the Governor's energy policy and one that has been adopted by the CEC and the Commission through EAP II. The Commission recognizes SCE's argument that, today, no legislation has been passed mandating that the IOU procure towards a 33% renewables target by 2020. However, the Commission agrees with Aglet that pursuing a 33% target is a policy goal of the Commission and one that should be pursued by the IOUs at this time. We acknowledge GPI's argument that accelerating the 20% renewables target from 2017 to 2010 suggests that higher future levels of renewable energy procurement are a goal of the Commission.
The Scoping Memo clearly directs the IOUs to describe how the EAP II goal of 33% renewables by 2020 will be achieved. The Commission agrees with DRA that all three IOU's 2006 LTPPs provide insufficient information for the Commission to accurately assess how the IOUs will achieve a 33% renewables target by 2020. We acknowledge SDG&E's comment, however, that the time between issuance of the Scoping Memo and delivery of plans was quite short, and we expect that future LTPP schedules will better accommodate the IOUs' ability to more fully reflect on these issues.
We do not believe that a GHG target should be the single overarching policy goal, with utilities allowed full flexibility regarding their use of renewable resources to achieve that goal. While reduction of GHG emissions is clearly one of the key drivers for increasing the RPS goal, the RPS program was established in recognition of several other benefits to renewable energy development, as well. We agree with PG&E, however, that further analysis is needed regarding the feasibility and cost of a 33% renewables target. We direct parties to work with ED staff to refine a methodology for resource planning and analysis that will allow them to adequately address the issue of a 33% renewables target by 2020 in subsequent LTPPs.
The Commission recognizes that there are many challenges associated with achieving a 33% renewables target. SDG&E, backed by AReM, suggests that RECs may be a necessary component to achieving such targets. However, the consideration of RECs is out of the scope of this proceeding and is being addressed in R.06-02-012. The Commission further appreciates the IOUs' discussions of the need for transmission to reach the 33% goal. As noted in this decision's section on the 20% by 2010 goal, however, we found that these discussions did not include the detail, integrated approach, or forward-thinking suggested in the Scoping Memo. We expect these sections to be much more robust in subsequent LTPPs and expect that parties will work to make RETI useful in this regard.
4.6. Implementation of MRTU
In late 2001, the CAISO instituted a program of comprehensive market redesign called "MRTU" (Market Redesign and Technology Upgrade - formerly known as MD02) intended to enhance performance of the CAISO's core functions (reliable, nondiscriminatory transmission). This was to be effected, in part, by resolving congestion caused by the CAISO's zonal congestion management through the use of a Full Network Model (FNM), which the CAISO claims will accurately model the grid, and an Integrated Forward Market (IFM) based on Locational Marginal Pricing (LMP).
Under MRTU, there will be a day-ahead market, which will be an integrated CAISO market for energy and ancillary services, as well as congestion management, and, if necessary, Residual Unit Commitment (RUC); an hour-ahead scheduling process (HASP), which is an opportunity to make scheduling adjustments (but is not a full-settlement market); and a real-time imbalance market with optimized economic dispatch. The CAISO will also impose Market Power Mitigation measures, including a damage control bid cap and procedures to address local market power.
MRTU implementation is currently scheduled for March 31, 2008, although it is possible that implementation may be delayed. According to the CAISO, MRTU represents important, incremental improvements to the existing market design, improves price signals to allow for more efficient generation dispatch, and it does so in a way that protects customers, and should lower costs by increasing the efficiency of the CAISO's transmission grid operations.
Some of the most important elements of MRTU are to:
· fix market design flaws;
· eliminate infeasible schedules;
· use a more comprehensive model of the transmission grid;
· add a financially binding day-ahead market;
· adopt locational marginal pricing for suppliers and for improved congestion management;
· improve transmission rights;
· require compliance with the Long-Term Firm Transmission Rights Final Rule;
· increase bid caps incrementally;
· provide local market power mitigation; and
· build upon resource adequacy.
Precise procedures to be used by the CAISO and market participants to implement MRTU are proposed for the CAISO's Business Practices Manuals (BPM). At the time of this decision, some BPMs are still being developed and finalized. Therefore, the exact processes and procedures that market participants will need to comply with are, as of yet, unknown.
The Scoping memo directed the IOUs to describe the impact of MRTU implementation on procurement practices and procedures.
In comments, PG&E represents that the CAISO's "new and improved" markets will not significantly alter its procurement processes. However, PG&E does, based on current MRTU market designs, seek Commission approval to update the description of two existing authorized products to assure compatibility with specific new aspects of MRTU. In particular, PG&E requests the following:
Proposed Modified Description | |
Transaction |
Description |
Electricity Transmission Products |
Purchase or sale of transmission rights, products (e.g., LT-FTRs, CRRs, losses), or the use of locational spreads. |
Financial Swaps |
An agreement to exchange one type of pricing for another. Examples include fixed-for-floating swaps, basis swaps, and payment obligation swaps (e.g., CAISO IFM Uplift Load Obligations). Swaps are financially settled directly with a counterparty or may be financially cleared through a financial clearing house. |
PG&E explains that, under MRTU, the CAISO will assure bid cost recovery for suppliers selling into the CAISO markets; to the extent market revenues are insufficient to recover bid costs the CAISO will provide suppliers with uplift payments to guarantee bid cost recovery. The CAISO will in turn collect the uplift payments through cost allocations to Scheduling Coordinators ("SC").
PG&E further requests that the Commission modify the existing approved Electricity Transmission Product description, as provided for in D.02-10-062 and D.04-12-048, to clarify that this existing product is adequate to address transmission congestion and loss aspects of MRTU. The primary feature of the CAISO's proposed market redesign is an integrated market that involves the simultaneous optimization of energy and ancillary services procurement based on LMP in a process that will also manage transmission congestion and transmission losses. PG&E states, in testimony, that MRTU will provide for the ability to hedge transmission losses through Long-Term Firm Transmission Rights (FTRs) and Congestion Revenue Rights (CRRs).278 While similar hedging products for transmission losses do not exist at this time, these have been presented for consideration at the CAISO and may develop in the future. To address these MRTU market design features, PG&E requests a modification and clarification to the existing product description for Electricity Transmission Product.
With the above requested product modifications PG&E states that it will have sufficient Commission authority to participate in new transactions significant to the current CASIO scope of MRTU.
However, PG&E further requests Commission approval for new products that may be needed during the CAISO's finalization of MRTU which the CAISO considers mandatory for MRTU market participation. PG&E states that for the time being, it will identify these new products as "Non-Discretionary Products Required by MRTU."
Product |
Description(a) |
Prior Authorization | |
28 |
Non-Discretionary Products Required by MRTU |
MRTU Products, which may be created by the CAISO during the finalization of MRTU that would be mandatory in order to participate in MRTU. |
New transaction requested in Volume 2, Section I.B.3 Impact of MRTU on Procurement Practices. |
PG&E requests authority for "Non-Discretionary Products Required by MRTU" since there may be insufficient time to seek and obtain Commission approval through an advice letter filing between MRTU design finalization and MRTU market initiation. However, if there is adequate time for such a filing, PG&E will do so.
SDG&E claims that while MRTU will be a "sea change" for the CAISO's systems and operations, its impact on SDG&E procurement as outlined in its LTPP will be minimal. The changes in MRTU will be limited to the mechanics of scheduling and settlements. It will not significantly alter the major elements of its plan, such as SDG&E's positions or the manner in which SDG&E procures because IOUs are encouraged to procure most of their resources outside of spot markets. With the introduction of a CAISO day-ahead market (which would fall within the Commission definition of "spot" markets), SDG&E suggests that the Commission abandon the current guideline of "5% or justify" in the spot market.
SCE's testimony regarding the implementation of MRTU focuses on two main themes: (1) the way that LSEs meet their RA requirements,279 and; (2) implementation of virtual bidding.280 SCE argues that these two elements of the CAISO's new system will impact the way in which it conducts business with the CASIO markets, and thereby how it complies with Commission procurement policies and practices.
SCE asks for specific authority to modify its procurement plan to include virtual bidding once sufficient information regarding the details of virtual bidding rules have been established.
TURN believes that it is clear that the implementation of the CAISO's MRTU project will have dramatic impacts on the California electricity market. However, predicting exactly what those impacts will be is at best an uncertain endeavor. TURN believes that this Commission should continue to closely monitor the MRTU process and take appropriate positions on behalf of ratepayers in the CAISO stakeholder process.
There is no doubt that MRTU will greatly impact the CAISO's markets. We note that this is precisely the point of this endeavor. As a result of the redesign effort there are a number of elements of MRTU that may impact the procurement practices or costs of the IOUs. As an example, the CAISO created CRRs to be financial obligations that can be utilized by market participants to hedge transmission congestion.281 Other MRTU design elements will have additional impacts on the CAISO and market participants.282
Additional market design features are planned for implementation after the initial start of MRTU. The FERC has ordered the CAISO to develop scarcity pricing whereby prices for both reserves and energy would increase automatically as shortages increase. Scarcity pricing is intended by FERC to increase the participation of demand response, among other things. The CAISO must also incorporate Virtual Bidding (also referred to as Convergence Bidding); a process by which virtual supply can be sold and virtual demand purchased in the Day-Ahead market and subsequently settle as deviations in the real time market.283
Currently, it does not appear that MRTU will significantly impact the resource planning and the majority of the procurement processes that typically happen in time frames that begin a substantial length of time prior to the day-ahead and day-of focus of the MRTU market changes. However, what does occur in the MRTU time frame are the least-cost-dispatch processes and decisions carried out by the IOUs. In D.02-09-053, the Commission reiterated the importance and requirements to perform the scheduling and dispatch of utility portfolios in a least cost manner. In an attempt to comply with this Commission decision, the IOUs dispatch resources and utilize market purchases to manage the short-term needs of their portfolio. The CAISO's new day-ahead market represents one additional option along with the other existing bilateral exchanges, brokers and direct transactions in executing least-cost dispatch. All of these markets may legitimately be used. At this time, it does not appear that the MRTU spot market reforms and new market elements will significantly alter the results of the least-cost-dispatch process. However, we will closely monitor the implementation of MRTU process and, if necessary, make appropriate changes to our procurement rules.
We now turn to the specific authorization requests of each of the IOUs. SDG&E suggests that the Commission abandon the current guideline that not more than 5% of an IOUs market purchases should be conducted in the spot market. If an IOU exceeds the 5% limit it is required to submit justification in the quarterly compliance filings. SDG&E's reason for suggesting this policy change is that the CAISO day-ahead market would fall within the Commission's definition of spot markets. Therefore, SDG&E essentially concludes that the 5% limit on spot transactions may be set too low. While we agree that the new day-ahead market administered by the CAISO may prove to be attractive means for the IOUs to manage its portfolio on a short term basis, we do not find compelling evidence to change our current regulations. We do not believe that the requirement that IOUs justify any spot purchases over a 5% threshold is burdensome. We will continue to monitor the impact of the CAISO's market reforms and adjust our rules if deemed necessary.
SCE asks for authority to modify its procurement plan to include virtual bidding once sufficient information regarding the details of virtual bidding rules have been established.
We understand that the CAISO is currently undergoing the process of defining the rules under which it plans to implement virtual bidding. Once those rules have been established and approved, it may be necessary for the Commission to revisit the procurement polices in place. We see no reason to modify our procurement polices to allow SCE to include virtual bidding at this time. Once more detailed information regarding virtual bidding is available, each of the IOUs can file for a modification to its procurement plan using the appropriate forum.
PG&E is seeking authority to modify the description of two existing products that were previously approved by the Commission, and to add a new MRTU-related product. PG&E states that it is actively seeking to manage the challenges that full implementation of MRTU may present and is seeking Commission approval of products that will allow it to more effectively do so. We find PG&E's request to modify the existing product definitions of "Financial Swap" and "Electricity Transmission Products" to be reasonable. However, we will impose reporting requirements upon PG&E associated with these products. PG&E is directed to include details regarding transactions that involve these products in its Quarterly Compliance Reports. If PG&E determines a need to procure transmission related products that fall outside this approved definition it is directed to file an Advice Letter before engaging in procurement activities.
PG&E further requests Commission approval for new products that may be needed during the CAISO's finalization of MRTU which the CAISO considers mandatory for MRTU market participation. PG&E states that for the time being, it will identify these new products as "Non-Discretionary Products Required by MRTU." We do not find this request by PG&E to be reasonable. This request would essentially allow PG&E to procure any product that it deems necessary for participation in the CAISO market without seeking further Commission approval. PG&E's reasoning for making this request also appears to be flawed. PG&E requests authority for "Non-Discretionary Products Required by MRTU" since there may be insufficient time to seek and obtain Commission approval through an advice letter filing between MRTU design finalization and MRTU market initiation. However, if there is adequate time for such a filing, PG&E will do so. We note that MRTU redesign has been an ongoing process since early 2001. We, therefore, see little basis for the assumption that there might not be enough time to seek approval for additional procurement authority through an advice letter filing. To the extent that PG&E requires additional procurement authority pursuant to the implementation of MRTU it is instructed to follow Commission procedure for seeking such additional authority.
4.7. Confidentiality
The IOUs, intervenors and the Commission continue to weigh the competing interests of confidentiality versus open and transparent filings and decisions. In D.04-12-048, we referenced an Amended Protective Order (APO) that had been issued by an ALJ, and we determined that that APO controlled confidentiality issues in R.04-04-003. We acknowledged that we knew more work was needed by the parties and the Commission to move towards the more open and transparent decision making that would foster the competitive, hybrid market we envisioned.
Between the 2004 and 2006 LTPP filings, we initiated a Rulemaking to thoroughly vet the competing positions on confidentiality, and in June, 2006, we issued D.06-06-066 that established guidelines for the treatment of certain categories of procurement-related information and created a Matrix of the types of information that warranted confidential treatment. To further provide guidance on the treatment of confidential information, and in particular on the topic of Protective Orders, the Commission issued D. 06-12-030 on December 14, 2006-three days after the IOUs filed their LTPPs.
When each IOU filed its LTPP on December 11, 2006, they each concurrently filed a Motion to File Under Seal. On May 2, 2007, per ALJ ruling, the Motions to File Under Seal were granted, with modifications. First, to the extent a utility complied with the requirements of D.06-06-006 and set forth data that falls within the categories of the Matrix, the data was allowed to be filed Under Seal. Following the direction from D.06-12-030, parties that were authorized to see the data filed Under Seal, were to be allowed to do so under a Protective Order that was consistent with D.06-12-030.
It appears, however, that there is no solution to the confidentiality debate that will satisfy all parties. The IOUs still filed two sets of LTPP plans: one set complete with all the data and a redacted version. Even if the IOUs are complying with Commission directives, the market participant parties still allege that they are hobbled in their ability to review or challenge the data that supports the plans. All parties are aware of the continuing tension that confidentiality issues raise, especially as the IOUs and the market participants are often competing head-to-head.
In particular, some intervenors ask the Commission to require the IOUs to release more data than the IOUs voluntarily circulate. AReM would like to review the IOUs' percentage of total load in their service territories served by DA. CAC/EPUC are concerned that their customers may be asked to pay stranded costs, yet the models and data used by the IOUs to derive the stranded costs is not available for review or challenge by the very parties who have to pay the costs.
There is not a consensus among the intervenors and IOUs on whether or not the names of winning bidders from a RFO should be released, and if so, when. The release of the winning bid information would provide more transparency to the bidding process and would allow non-selected participants in the RFO process to see why their bids were not accepted. Parties such as WPTF advocate requiring the release of the winning bid information, but understand the need for a utility to keep the information confidential until key elements of the bidder's project have been secured. However, while a utility might need some flexibility on when to release the bid information, WPTF is concerned that unless the Commission requires the release of the information within some time limit, the information might never be released. Aglet recommends that the Commission direct the IOUs to release the bid information at the time the IOU files an application.
We are convinced by the arguments presented by intervenors that some direction is needed from the Commission on the subject of release of winning bid information. We find that that it is reasonable for the IOU to keep the identity of the winning bidder confidential until key commercial elements have been finalized. However, we also find it reasonable that the IOU must publicly reveal the names of winning bidders, a description of the product, and the contract term, within 90 days of when the IOU files an application with the Commission for approval of the contract. As WPTF recommends, if an IOU has filed an application, but key commercial terms have not been finalized within the 90-day time frame, the IOU should withdraw the application and re-apply once it can release the bidder's identity and key. The IOU does not have to publicly reveal the actual contract.
While we continue to wrestle with other vexing issues on the topic of confidentiality and how to promote an open, competitive market, and protect the ratepayer, we do not find it necessary, or prudent, to make any further findings on the topics of confidentiality or Protective Orders in this decision. We have an open docket, R.05-06-040, to address those issues.
233 For the purposes of this discussion, the term UOG includes, but is not limited to, utility-built, Engineer, Permit and Construct (EPC), and Purchase and Sale Agreement (PSA) acquired resources. When a specific acquisition path is under consideration, it is referenced (i.e., `utility-build' rather than `UOG'). In addition, the discussion of UOG in the IOU LTPPs and subsequent intervenor and IOU testimony generally focused on utility ownership of conventional generation resources. The Commission recognizes that there are additional factors associated with utility ownership of renewable and other loading order or non-conventional resources that have not been fully vetted in this proceeding. The appropriate treatment of UOG for accomplishing resource-specific policy goals will be identified within the appropriate proceedings, and the treatment of utility ownership of conventional generation in this LTPP decision does not prejudice those proceedings in any manner.
234 IEP Opening Brief, pp. 58-59.
235 TURN Opening Brief, pp. 26-27.
236 This code of conduct would be very similar to the codes of conduct and bans on preferential access to information that apply between a utility and its generation affiliates. Therefore, the internal IOU functions involved in project development and bid preparation. Thus, if a utility were soliciting turnkey bids or EPC contracts as well as PPAs in a given solicitation, the individuals performing the bid evaluation would have to be functionally separated from the individuals preparing the bids (or the cost estimates) for projects that would ultimately be utility-owned (we note that some of the utilities already do this). Under this restriction, the employees developing the utility-owned project would be barred from access to any evaluation protocols, input assumptions, or bid information not made generally available to outside bidders. This approach would provide assurance that the utility could not use "inside information" to the advantage of its own project, without requiring the publication of every detail of the bid evaluation protocol.
237 It should be noted that in this context Utility build bids do not include PPAs with affiliates.
238 For example, increased requirements on the IOU to consult with the IE, PRG and ED staff on the development and implementation of an RFO including the bid evaluation criteria.
239 The categories listed here are not permanent. As our procurement experience grows and processes evolve the needs highlighted in these five categories may change.
240 As noted in Section 1.1, preferred resources in order of preference are energy efficiency, demand response, renewables, distributed generation and clean fossil-fuel. However, a utility may only develop a clean fossil-fuel UOG outside of the RFO process if it utilizes an advanced or emerging technology that the market is unlikely to develop.
241 We note that one method in which the IOU could demonstrate that the resource really is favorably priced is by subjecting the resource to a "market test" by conducting a competitive solicitation.
242 D.04-12-048 at p. 128.
243 D.04-12-048 at p. 129.
244 The issue on rehearing as stated in D.05-09-022 was "the 50/50 sharing provisions related to construction cost savings ... "
245 SCE reported to the ALJ on January 5, 2007, that the meet-and-confer discussions did not reach a resolution and the 50/50 share issue needed to be further explored as part of the LTPP proceeding.
246 Ex. 7 at I-3 - I-6.
247 SCE proposes to consider new utility-owned generation under two broad cases. In the first case, SCE proposes to own generation if competitive market alternatives are not readily available. In the second case, based on an evaluation of competitive market alternatives and/or in consideration of portfolio diversity, SCE will own the generation if utility ownership offers greater value and/or benefits to its customers.
248 These changes might occur during negotiation, after the contract is entered into, or after delivery of the product regardless of who owns the generation.
249 And if the utility were to pursue ownership under this mechanism, there is a perverse incentive for the utility NOT to make cost saving modifications (during or after construction) that would clearly be in the customer's best interest yet require additional upfront capital not covered in the initial bid price (e.g., improvements that lower heat rate, lower auxiliary load, increase capacity, lower long-term O&M, etc.).
250 The Gateway settlement adopted an initial capital cost estimate of $295 million. If the actual cost of Gateway is less than $305 million, the total amount goes into rate base without further review. If the amount is between $305 and $345 million, PG&E can recover the $305 million and 90% of the amount over $305. If the amount exceeds $345 million, PG&E can only recover any amount above $345 million subject to a finding of reasonableness by the Commission. If the actual cost is less than $295 million, customers will receive 100% of the savings.
251 SDG&E proposes that for changes in price occurring after initial Commission approval of a UOG asset and prior to commercial operation, utility shareholders should be held without gain or loss for changes in price by 5% above or below the Commission-approved price. For the next 10% price increase or reduction, shareholders should be responsible for 10% of the additional costs or rewarded for 10% of the additional savings above the 5% threshold. The full savings below or full costs above the 15% threshold would be garnered or borne by customers. Costs above the 15% threshold would be subject to recovery through a regulatory review process.
252 We note that, generally speaking, resource attributes desired by the IOU or the presence or absence of these attributes needs to be factored into the bid comparison process; the Commission will have little tolerance for the appearance of a litany of "adders" on winning bids that may have been built into other bid prices.
253 SCE's Rule 3.A.1(b)(3) indicates the GHG adder is fixed at $8/ton, when in fact the annualized value, based on avoided cost, should rise to $10/ton beginning in 2007, according to D.05-04-024, COL 27, p. 29.
254 According to SCE Rule 9.A.2, all RMR units should count toward Local and System RAR, but D.06-06-064, p. 47, states that Condition 1 RMR units should not count toward System RAR.
255 AB 1576, (Stats. 2005, Ch. 374, Sec. 2. Effective January 1, 2006), codified in the Pub. Util. Code as Section 454.6.
256 PG&E estimated CO2 emissions generated by its portfolio under each plan and scenario combination. Forecasts were calculated by adding the CO2 emissions associated with the amount of natural gas used for PG&E's existing resources, the CO2 emissions estimate for fossil-fuel burning QFs, and the CO2 emissions estimate for other market purchases of electricity and for new natural gas burning generic resources needed to cover the open position. Two metrics were presented for measuring the performance of its procurement plans: (1) average annual metric tons per year of CO2 emissions from each plan under different scenarios; and (2) average carbon efficiency in pounds per megawatt-hour of load plus avoided load associated with CEE and DG included in the plan.
257 SCE, for each candidate plan, measured the total portfolio emissions of CO2, which was used as a proxy for the overall GHG emissions of the portfolio. To measure environmental sensitivity, SCE did a stochastic analysis of total emission production over the ten-year planning horizon for the Required Plan and the Best Estimate Plan at the expected level (stochastic average), using a set of input assumptions for emission rates for current and future resources. SCE's calculations show that the Required Plan yields an emissions rate that is 9% lower than the Best Estimate Plan, which SCE feels is a close comparison between plans. SCE also feels that the emissions rate found in the Required Plan would come at a considerable cost to customers due mainly to the new transmission infrastructure needed to deliver additional renewable power. SCE feels that there are much more cost effective GHG offsets including coal-mine methane flaring, landfill methane flaring, SF6 leak management, anaerobic digestion and forestation projects.
258 Measurement is changed from SDG&E's original plan filing to correct a typographical error.
259 SDG&E makes the following assumptions to determine its GHG emissions:
1) All renewable resources, including wind, solar, bio-mass, bio-gas and geothermal were assigned no GHG emissions. Nuclear was also assigned no emissions.
2) Natural gas fueled emissions were determined based on fuel usage at a rate of 117 lbs/MMbtu.
3) Coal emissions (one existing contract) were based on fuel usage and were assigned an emissions rate of 205 lbs/MMbtu.
4) QFs were assigned an emissions rate of 639 lbs/MWh. (Most contracts are combined heat and power).
5) For the three DWR contracts, SDG&E assumed an emissions rate of 915 lbs/MWh.
6) The LTPP assumes that SDG&E will periodically make economy energy purchases from the market. For this plan, SDG&E assumes that all energy is purchased from the market, rather than from direct suppliers, and assigns an emissions rate of 915 lbs/MWh.
7) For SDG&E economic sales, SDG&E deducted from its total emissions the amount of emissions associated with those sales at the same rate as purchases (915 lbs/MWh).
260 PG&E Volume II at I-15.
261 The May 2, 2007 R.06-02-013 ruling determined that PG&E's ERRP proposal would be more appropriately submitted as a separate application. PG&E and SDG&E subsequently filed a joint application, A.07-07-015.
262 SCE Volume 1B at 74.
263 SCE Volume 1B at 80.
264 We note that SB 1036, effective January 1, 2008, abolishes the current SEP process and redistributes PGC money among the large utilities.
265 SCE Volume 1B at 81.
266 SCE Volume 1B at 86.
267 SCE Volume 1B at 88.
268 SDG&E Volume 1 at 191.
269 SDG&E Volume 1 at 192.
270 Aglet Testimony.
271 AReM Testimony.
272 DRA Testimony.
273 CEERT Testimony.
274 PG&E Testimony.
275 Based on a 2016 target of 28% and a capacity factor of 50%, the assumed shortfalls in 2016 ranged from 481 MW (Scenario 3) to 1,074 MW (Scenario 1).
276 SDG&E's preferred plan yields 22% renewable deliveries in 2010, increasing to 25% in 2013, and declining to 21% in 2020.
277 CEC Testimony.
278 These products can be obtained through allocations and auctions from the CAISO and additionally through secondary bilateral trading.
279 SCE's testimony regarding this issue digresses into a discussion of centralized capacity markets. The ALJ, on May 2, 2007, ruled that this issue was currently being addressed in R.05-12-013 and therefore is outside the scope of this proceeding. Therefore, we will not address it in this decision.
280 "Virtual bidding" is a practice by which an entity can participate in the day-ahead and real-time markets without any physical generation or load. A virtual bid into the day-ahead market is coupled with an equal and opposite transaction in the real-time market. Thus, a virtual load bid in the day-ahead market, if successful, will result in an obligation to pay the awarded amount at the day-ahead price, and a corresponding right to be paid the same amount at the real-time price (in the case of a virtual load bid in the day-ahead market, the equal and opposite transaction is a virtual real-time sale).
281 We note that all three IOUs have sought Commission approval for the use of LT - CRRs in AL 2142 (SCE), AL 3095 (PG&E) and AL 1920 (SDG&E; and for CRRs in AL 2141 (SCE), AL 3106 (PG&E) and AL 4124 (SDG&E).
282 For example, the CAISO intends to impose constraints in order to ensure that the required amounts of ancillary services are reasonably distributed across the system and, if system conditions merit, it may identify sub-regions within the CAISO Control Area to ensure appropriate distribution and effectiveness of the procured ancillary services. The CAISO is in the process of establishing the process to define the regions or regional targets.
283 With Virtual Bidding, the actual price differences between the Day-Ahead market and real time market will determine if the holder makes or loses money. FERC has suggested that convergence bidding mitigates market power and provides other benefits. While convergence bidding does not create either real added supply or demand, these bids do contribute to the determination of market clearing prices. To the extent convergence bidding is implemented by the CAISO, it may be necessary and important for California's IOUs to participate and therefore, this Commission's procurement rules may need to be augmented.
